IR 05000336/1998005
| ML20199C642 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 01/07/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20199C636 | List: |
| References | |
| 50-336-98-05, 50-336-98-5, 50-423-98-05, 50-423-98-5, NUDOCS 9901190037 | |
| Download: ML20199C642 (57) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION 1 l
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I Docket Nos.:
50-336 50-423
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. Report Nos.:
98-05 98-05 License Nos.:
DPR-65 NPF-49 i
Licensee:
Northeast Nuclear Energy Company P. O. Box 128 Waterford. CT 06385 Facility:
Millstone Nuclear Power Station, Units 2 and 3 inspection at:
Waterford, CT Dates:
October 6,1998 - November 23,1998 Inspectors:
T. A. Eastick, Senior Resident inspector Unit 1 l
D. P. Beaulieu, Senior Resident inspector, Unit 2
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A. C. Cerne, Senior Resident inspector, Unit 3 l
P. Cataldo, Resident inspector, Unit 1 S. R. Jones, Resident inspector, Unit 2 8. E. Korona, Resident inspector, Unit 3 N. J. Blumberg, Reactor Engineer, RI j
J. W. Andersen, Project Manager, HC D. A. Dempsey, Reactor Engineer, RI i
J. H. Williams, Senior Operations Engineer, RI C.I.. (E!!, Reactor Engineer, RI
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Approved by:
Jacque P. Durr, Chief l
Millstone inspection Branch l
Region 1 l
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9901190037 990107 PDR ADOCK 05000336
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TABLE OF CONTENTS EXECUTIVE SU M M ARY................................
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U2.1 Operations
..................................................1 U2 01 Conduct of Operations............................... 1 U2 03 Operations Procedures and Documentation................. 1 U2 05 Operator Training Qualification
.........................3 U2 08 Miscellaneous Operations issues (92700)............. 7 U 2.ll M aintenan ce................................................ 10 U2 M1 Conduct of Maintenance........
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U2 M8 Miscellaneous Maintenance issues..................... 12 U 2.lli Engineering................................................ 1 5 U2 E8 Miscellaneous Engineering issues....................... 15 U3.1 Operations
.................................................28 U301 Conduct of Operations.............................. 2 8 U3 07 Quality Assurance in Operations
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U3 08 Miscellaneous Operations issues (92700)................. 33 U 3. Il M ain t en a n ce................................................ 3 4 l
U3 M1 Conduct of Maintenance............................. 34 U3 M2 Maintenance and Material Condition of Facilities and Equipment
.........................................36 U3 M8 Miscellaneous Maintenance issues...................... 37 l
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U 3.lli Engineering................................................ 3 9 l
U3 E7 Quality Assurance in Engineering Activities................ 39 l
U3 E8 Miscellaneous Engineering issues....................... 40 l
IV Plant Support
.................................................43 F2 Status of Fire Protection Facilities and Equipment........... 43 F3 Fire Protection Procedures and Documentation
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l V. Management Meeting s........................................... 4 6 j
X1 Exit Meeting Summary..............,........,..... 46 j
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EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 336/98-05; 423/98-05 Operations At Unit 2, the licensee failed to adequately translate design information regarding e
reactor building closed cooling water (RBCCW) flow to the shutdown cooling heat exchanger to the operating procedure used to control RBCCW system configuration.
This negative finding is of minor safety significance because operation at power in an improper RBCCW system configuration was found to be unlikely and because the
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effect of operation in an improper configuration on post-accident containment pressure was found to be minimal. Therefore, this failure constitutes a violation of minor significance and is not subject to formal enforcement action. (Section U2 03.1)
The Licensed Operator Requalification Training (LORT) program at Unit 2 met e
regulatory requirements with no significant weaknesses identified. The LORT
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program content was balanced and met the needs of the operators. The simulator scenarios and written examinations administered during the first tnree weeks of the cycle were independent with no overlap. This was considered to be a strength.
The evaluations of the simulator scenarios and job performance measures (JPMs)
were objective and thorough. Minor problems on evaluation consistency were identified. The feedback process as part of the systems approach to training (SAT)
program was found to be effective. The licensee was found to be meeting the regulatory requirements associated with licensed operators that were reviewed.
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Based upon current staffing levels, the inspectors determined that Millstone 2 was
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meeting licensed operator staffing requirements. Planned licensed operator I
increases will supplement the licensed operator pool. SIL 13, MC 0350, item C.3.3.a, remains open however, pending further inspection and closure of other manual chapter 0350 sub-items captured under SIL 13. Overall, the licensee was effectively providing training for licensed operators and evaluating their performance. SIL14, MC 0350, item C.3.3.c, remains open, however, pending i
further inspection and closure of other manual chapter 0350 sub-items captured j
under SIL 14. (Section U2.05.1)
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e At Unit 2, the licensee has implemented acceptable corrective actions to procedurally prohibit future movement of the heavy dummy fuel assembly (HDFA)
over irradiated fuel, which is in violation of the current TS 3.9.7 limiting condition for operation. Therefore, LER 50-336/97 10-00 is closed. Past movement of the HDFA over irradiated fuel was in violation of TS 3.9.7. This non-repetitive, licensee-identified and corrected TS violation is being treated as a non-cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. (Section 08.1)
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e Following a review of the Unit 2 Emergency and Abnormal Operating Procedures revision process, the NRC concluded that overall, the licensee has appropriate i
measures established such that procedures necessary to support startup of Unit 2
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will be ready for use by operators. Therefore. Significant items List No.10 is considered closed. One concern that was identified during this inspection was the lack of a stand alone procedure for a loss of containment integrity as required by Technical Specification (TS) 6.8.1 and Regulatory Guide (RG) 1.33 ;this is considered a minor violation. URI 50-336/97-203-04 is considered closed. To address the violation, the licensee has committed to develop an abnormal operating procedure for loss of containment integrity, and to perform a review of RG 1.33 to ensure the necessary procedures are in place such that compliance with TS 6.8.1 l
and RG 1.33 is established. (Section U2.08.2)
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Unit 3 operators properly responded to high conductivity levels in the secondary l
system and manually tripped the reactor on October 28. Operators took appropriate command and control of the plant to place it in a safe condition in accordance with procedures. Close coordination and communication was observed among the l
operations, chernistry, engineering and maintenance departments during the shut l
down and methodical troubleshooting activities. Although the plant was designed
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to operate with more than one waterbox out of service, the licensee conservatNely maintained the plant shut down until the leaking condenser was identified, based on chemistry results. The specific, leaking "C" condenser tube was identified and plugged shortly after restart. (Section U3.01.1)
Maintenance
The NRC concluded that the maintenance on the medium voltage breaker located in
Unit 2 Cubicle A410 was performed in an acceptable manner using approved l
procedures. Also, the licensee had acceptable justification for the level of maintenance performed on individual breakers. (Section U2.M1.2)
At Unit 3, review of inspected troubleshooting, failure analysis, and maintenance e
l repair activities revealed the implementation of adequate controls by the licensee.
l The proper use of a temporary mooification, including a safety evaluation, was verified by the NRC inspector. The inspector determined that, based upon the observed component conditions for both inverter No.1 and 3FWS*CTV41B, as well the continued monitoring of egnpment status by the licensee, the scope of licensee maintenance / repairs for these components was deemed appropriate. (Section U3.M2.1)
Licensee corrective actions for three Unit 3 LERs, which involved testing of logic e
circuits, environmental qualification of installed parts, and vital area barrier maintenance, were determined to be acceptable. The corrective measures were i
commensurate with the safety significance of the self-identified problems and included consideration of long term programmatic initiatives to preclude problem l
recurrence. Reportability, timeliness, event analysis requirements have been met.
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These non-repetitive, licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Pokcy. LERs 97-017-02, 97-050-00, and 97-S001-00 are hereby closed as non-
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cited violations, NCVs 50-423/98-05-05, 06, & 07, respectively. (Section
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Engineering At Unit 2, the licensee effectively addressed the specific concerns associated with e
URI 50-336/96 04-11 and eel 50-336/96-04-10, which involved the adequacy of reactor building closed cooling water (RBCCW) system flow to various safety-related components. The NRC found that the modeling, calculations, and testing that were performed acceptably demonstrated the design adequacy of the revised RBCCW flow provided to safety-related components. URI 50-3306/96-04-11 and eel 50-336/96-04-10, as well as Unit 2 Significant items List No. 39.1, are considered closed. (Section U2 E8.1)
At Unit 2, the licensee's calculations and conclusions concerning possible cavitation e
and choked flow in the high pressure safety injection flow restriction orifices and
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throttling valves in response to Unresolved item 50-336/96-201-38 were acceptable. No violations were identified. URI 50-336/96-201-38 and Unit 2 j
Significant items List No. 39.2 are considered closed. (Section U2.E8.2)
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The NRC found that the licensee's self-assessment of the Material, Equipment, and e
Parts List (MEPL) Program to be of high quality and very self-critical, particularly regarding the disposition of MEPL-related non-conformance reports (NCRs). The licensee's previous self-F.ssessment, as well as several NRC inspection reports over the past two years, have discussed the inadequate justification in NCRs for the "use as is" disposition for MEPL upgrades. The NRC is concerned that at this point in the recovery process, the licensee has not been effective in addressing this concern.
Accordingly, Escalated Enforcement items 50-336/96-201-42 & 43, as well as Unit 2 Significant items List No.18, remain open. (Section U2.E8.3)
At Unit 2, the licensee's corrective actions have adequately addressed LER 50-e 336/97-05-00, which involved three deficiencies where instrument calibration requirements imposed by the ASME Boiler and Pressure Vessel Code,Section XI, were not met. This was characterized as a non-cited violation. LER 50-336/97-l 005-00 and Unit 2 Significant items List No. 49.2 are considered closed. (Section l
U2.E8.4)
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At Unit 2, the NRC determined that the licensee's disposition of Licensee Event l
Report (LER) 50-336/97-33 was acceptable. Revision 0 of this LER described that i
the engineered safeguards actuation system (ESAS) was inoperable because the l
power supply fuses in the Facility 1 and 2 actuation cabinets could have blown if an
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ESAS actuation were to occur, thereby preventing the actuation safety equipment.
Revision 1 of this LER described that additional testing showed that an ESAS l
actuation would not have caused the fuses to open. The NRC determined that the j
licensee's basis for determining that this potentially safety significant issue was no i
longer a concern was adequately supported. LER 50-336/97-33-00 & -01 and Unit 2 Significant items List No. 52 are considered closed. (Section U2.E8.5)
The licensee's corrective actions in response to a design deficiency in the tie roo e
assemblies for eight Unit 3 RSS expansion joints are acceptable. This licensee-v
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identified and corrected violation is being treated as a non-cited violation. LER 97-021-00 is considered closed. (Section U3.E8.2)
Plant Support The fire penetration seals that were sampled in Unit 2 were satisf actory with e
regards to physical damage, presence of required permanent damming material, shrinkage and separation. The quality and consistency of the work orders improved with the implementation of subsequent revisions to the procedure MP 2721N. An issue involving indeterminate seal fill depths remains unresolved. Additionally, the inspector identified a violation in which several penetration seals were not installed or repaired to a tested configuration, which resulted in a violation of the Millstone 2 fire protection requirement. (Section F2.1)
e The licensee conducted a comprehensive material shelf life self review at Unit 2 for fire penetrant sealant. The use of expired seal materials, which resulted from the failure to follow fire barrier seals installation procedures, constitutes a minor violation. (Section F3.1)
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Bcaprt Details Summarv of Unit 2 Status
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The unit was initially shut down on February 20,1996, to address containment sump
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screen concerns 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 are conducted in accordance with the regulations, the license, and the Final Safety Analysis Report. The Unit 2 reactor core remained off-loaded for the duration of the inspection period.
U2.1 Ooerations l
U2 01 Conduct of Operations
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l 01.1 General Comments (71707)
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l 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 l
other buildings housing safety-related equipment; and observations of several management planning meetings.
j Specifically, the inspector observed operational preparations, procedural adherence, and the control of shutdown risk during vital 4160 Volt and 480 Volt ac switchgear outages, and vital 125 Volt de switchgear outages for breaker overhauls. Throughout these evolutions,
the inspectors noted good sensitivity to special conditions and equipment outages that
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affected shutdown safety.
U2 03 Operations Procedures and Documentation 03.1 Control of Reactor Buildina Closed Coolina Water System Valve Positions
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Insoection Scooe (71707)
l The inspector evaluated licensee controls over the positioning of reactor building closed cooling water (RBCCW) system valves. This inspection involved interviews with operations and engineering department personnel, as well as a review of procedures and design documents associated with the RBCCW system.
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- Observations and Findinas While reviewing calculation 97-169, "MP2 RBCCW system Design Basis Flow Distribution,"
l the inspector noted that RBCCW flow to several components, including the shutdown l
cooling (SDC) heat exchanger, was specified as isolated during the post-accident injection j_
phase. With the SDC heat exchanger isolated, the containment air recirculation (CAR)
coolers receive RBCCW flow above their minimum design flow of 2000 gpm per cooler in i
i the post accident injection phase. However, unlike the other components, the RBCCW
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flow to the SDC heat exchanger is not automatically isolated by the safety injection actuation signal at the start of the post-accident injection phase. Therefore, RBCCW flow to the SDC heat exchanger must be manually isolated during normal operation at power to ensure sufficient RBCCW flow to the CAR coolers. Consistent with this statement, section 9.4.3.1 of the Millstone Unit 2 Final Safety Analysis Report states that, during normal operation, RBCCW flow is supplied to all components served by the system with the exception of the SDC heat exchangers and the engineered safeguards room coolers.
For the post-accident recirculation phase, the sump recirculation actuation signal automatically opens the air-operated SDC heat exchanger RBCCW outlet valves,2-RB-13.1 A and 2-RB-13.1B for the "A" and "B" SDC heat exchangers, respectively, in this mode of operation, the minimum design RBCCW flow to each SDC heat exchanger is 2000 gpm, which is a significant portion of total RBCCW header flow. The initiation of flow through the SDC heat exchanger causes a significant reduction in RBCCW flow to the CAR coolers. Flow balance testing of the RBCCW system indicated that RBCCW flow to the CAR coolers would be insufficient to meet post-accident containment analysis assumptions if RBCCW flow was provided to the SDC heat exchangers during the post-accident injection phase.
Because the SDC heat exchanger RBCCW outlet valves do not automatically close at the start of the post-accident injection phase and because flow through the SDC heat exchanger reduces flow through the CAR coolers, the inspector evaluated how the positions of valves 2-RB-13.1 A and 2-RB-13.1B were controlled during normal operation.
Form 2611C-2, "RBCCW System Alignment Checks, Facility 1," and form 2611D-2,
"RBCCW System Alignment Checks, Facility 2," list the positions of these valves as open/ closed with a reference to an explanatory note that states, "This valve should be open to support SDC operations. If SDC is not in operation, this valve is closed." The inspector found this position information adequate, but the position information did not
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convey that the SDC heat exchanger RBCCW outlet valves must be closed during normal operation to satisfy the post-accident containment analysis assumptions for CAR cooler flow during the injection phase.
Because the valve alignment checks are periodic rather than continuous, the inspector j
reviewed the system operating procedure, procedure OP2330A, "RBCCW System."
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Procedure OP2330A did not provide direction to control system configuration consistent with the post-accident containment analysis assumptions. Specifically, section 4.3 of procedure OP2330A, " General Procedure for Establishing or Isolating RBCCW Flow to Components Served by RBCCW System," neither required operators to maintain valve positions consistent with the system alignment check positions nor specified restrictions on system configuration.
r Precaution 3.5 of procedure OP2330A specified that a total RBCCW system flow for each header of less than 4000 gpm should be avoided by placing components in service as necessary. By opening both CAR cooler RBCCW emergency outlet valves in each header, operators normally maintain header flow in an acceptable range. Although the SDC heat exchanger is unlikely to be needed to avoid operation at low system flow rates, its use was not prohibited. Additionally, discussions with licensed senior reactor operators revealed
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that they were unaware of restrictions on the position af the SDC heat exchanger RBCCW outlet valves in operational modes 1, 2, or 3. Based on these findings, the inspector determined that procedure OP 2330A did not provide sufficient information to assure that the RBCCW system would be maintained in an acceptable configuration during normal operation at power.
The inspector discussed this concern with operations department personnel, and the operations department initiated condition report (CR) M2-98-3486 to document the concern. The concerns documented in this CR will be addressed through the licensee's normal corrective action process. In addition, the operations department initiated several procedure change requests to clearly specify the system configuration necessary to satisfy the design basis post-accident containment analysis assumptions.
In order to assess the safety significance of potential flow diversion caused by improper positioning of the shutdown cooling heat exchanger RBCCW outlet valve, the inspector reviewed an existing analysis of post-accident containment response with degraded RBCCW flow to the CAR coolers. This analysis indicated that the increase in peak containment pressure was minimal when RBCCW flow to the CAR coolers was reduced to values comparable to those that would exist when the SDC heat exchangers receive RBCCW flow, c.
Conclusions The NRC concluded that the licensee failed to adequately translate design information regarding RBCCW flow to the SDC heat exchanger to the operating procedure used to control RBCCW system configuration. This negative finding is of minor safety significance because operation at power in an improper RBCCW system configuration was found to be unlikely and because the effect of operation in an improper configuration on post-accident containment pressure was found to be minimal. Therefore, this failure constitutes a violation of minor significance and is not subject to formal enforcemerit action.
U2 05 Operator Training Qualification 05.1 Licensed Ooerator Recualification Trainina Proaram Evaluation (Undale - Unit 2 Sianificant Items List (SIL) Nos.13 and 14)
a.
Insoection Scoce (71001)
The inspectors evaluated the Millstone Unit 2 Licensed Operator Requalification Training (LORT) program including the following specific areas: LORT program content; written and operating test content; operating test administration; training feedback program effectiveness; and conformance with license conditions.
The inspectors assessed the adequacy of the licensed operator staffing levels in meeting requirements and licensee goals as part of SIL13, MC 0350, item C.3.3.a. In addition the inspectors assessed the effectiveness of simulator training as part of SIL 14, MC 0350, item C.3. _ _ _ _ _ _ _. _ _.
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Observations and Findinas f
LORT Proaram Content The inspectors reviewed the subjects covered in the 1997-1998 LORT cycles, including a
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sample of training on modifications and LERs. The licensee was effectively incorporating
appropriate topics in their LORT program. Operator interviews indicated that the operators
were getting the training required for them to do their jobs.
I The 1997-1998 training cycles contained a total of 480 hours0.00556 days <br />0.133 hours <br />7.936508e-4 weeks <br />1.8264e-4 months <br /> of training. Simulator training accounted for over 40% of this time; while training on various procedures accounted for about 60% of the total time.
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The licensee plans to use the lessons learned from the recent Unit 3 restart in preparation
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for the Unit 2 restart. Unit 3 restart problems included: missed surveillance tests; an
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inadvertent PORV opening during heat up; and a feedwater transient. This experience has
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been incorporated into the Unit 2 LORT program.
j Written and Ooeratino Test Content and Administration i
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The inspectors reviewed the written examination and operating tests for the week of
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November 16,1998 (3rd examination week of a 6-week cycle), and verified that the i
licensee followed the guidance in the examiner standards. The scenarios were well written
with excellent inter-related events. The inspectors noted that one job performance j
measure (JPM) designated as " faulted" did not meet the criteria in the examiner standards
for a faulted JPM. The licensee agreed with the NRC assessment and took appropriate action.
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I The inspectors reviewed the examinations given during the first two weeks of the cycle as
i well as the examination given the third week to assess examination overlap from week-to-week. No overlaps were noted on the written or simulator examinations.
l Four simulator scenarios were observed being administered to one shift and one staff crew.
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Crew performance on the simulator was good. There was a discernable difference in
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performance, as expected, between the shift and staff crews. The staff crew tended to
focus their efforts within the control room and often forgot or delayed investigating i
equipment problems in the plant. Both crews were good at correcting other crew members l
when verbal mistakes when made.
Simulator evaluations were conducted by one member of management from training and one from operations. The operations evaluator was actively involved in the scenario evaluation process. The two evaluators worked together well and did a good job in identifying the deficiencies in competencies displayed during the four scenarios. The evaluator debriefs accurately addressed major strengths and weaknesses of the operators.
The inspectors noted the following areas where the evaluations missed some performance problems:
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Although peer checks were conducted a number of times, they were not
consistently applied nTr commented on during the evaluations.
The preparations and pre-job briefings for a surveillance test were not consistent
between crews nor commented on in the evaluations.
The evaluators provided guidance to one crew on conservative decision making.
- Written expectations on conservative decision making were not clearly delineated as a standard for operating and evaluating this area.
The inspectors observed the administration of a number of JPMs, both in the simulator and in the plant. In general, the evaluators did a good job. Two minor inconsistencies with
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respect to the examination standards (NUREG 1021) were noted. For example, some evaluators did not exetly follow the scripted " cues". Also, the JPM cues did not always follow the words used in the procedures with respect to expected equipment response.
The inspectors noted that the licensee's efforts to keep the simulator current with the plant configuration was very good. It was clear from operator interviews and records reviews, that operator raised simulator fidelity issues were acted upon in a timely manner.
Trainina Feedback I
The training feedback process was found to be effective in capturing operator concerns and providing timely resolution. This finding was based upon operator interviews as well as review of training records associated with feedback.
Comoliance with License Conditions A review of records and discussions with licensee personnel four'd that the licensee was i
meeting the requirements of:
l 10 CFR55.53 for maintaining active operator licenses i
10 CFR55.21 for medical examinations of operators and i
10 CFR55.49 for operator participation in the LORT program.
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SIL 13. MC 0350, Item C.3.3.a (uodate)
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The inspectors reviewed documentation and discussed staffing levels with plant
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management. The inspectors determined that Millstone 2 is meeting staffing requirements given in the technical specifications and their company goals. Currently, there are 5 operational shift crews that include a total of 38 senior reactor operator and reactor operator licenses. Also, several staff licensed p3rsonnel are available to assist operations whenever it is deemed necessary by station managemen.
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Plans are in place to enroll six individuals in the next licensed operator initial training class, scheduled to commence in February 1999.
SIL 14. MC 0351. ltem C.3.3.c (Undalgl As discussed above, the inspectors observed the conduct of four simulator exams that were administered to two crews as part of their annuallicensed operator examinations.
Both crews and allindividuals passed the simulator portion of the examination. The evaluators were effective in identifying weaknesses, which were subsequently discussed with the crews during the debriefings.
The inspectors reviewed a recently completed self-assessment performed by both in-house and outside industry peers. The purpose of their assessment was to review simulator instructor skills and evaluate the effectiveness of training sessions. Their self-assessment indicated that progress had been made in improving the level of effectiveness during simulator training, and that simulator training was in line with industry standards.
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Conclusions The LORT program met regulatory requirements with no significant weaknesses identified.
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The program content was balanced and met the needs of the operators. The simulator scenarios and written examinations administered during the first three weeks of the cycle were independent with no overlap, and were consideredjo be a strength. The evaluations of the simulator scenarios and JPMs were objective and tnorough. Minor problems on evaluation consistency were identified.
i The feedback process as part of the systems approach to training (SAT) program was
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found to be effective.
The licensee was found to be meeting the regulatory requirements associated with licensed
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l operators ;for example, Millstone 2 was meeting licensed operator staffing requirements.
Planned licensed operator increases will supplement the licensed operator pool. SIL item
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13, MC 0350, item C.3.3.a, remains open, however, pending further inspection and closure l
of other manual chapter 0350 sub-items captured under SIL13.
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Overall, the licensee was effectively providing training for licensed operators and evaluating j
their performance. SIL 14, MC 0350, item C.3.3.c, remains open, however, pending
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further inspection and closure of other manual chapter 0350 sub-items captured under SIL f
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U2 08 Miscellaneous Operations issues (92700)
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08.1 (Closed) LER 50-336/97-010-00: Heavy Dummv Fuel Assembiv and Handlina Tool
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Weiaht Exceeds Technical Soecification Limit a.
insoection Scoce (92700)
The inspector reviewed the licensee's corrective actions to address Licensee Event Report
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(LER) 50-336/97-10-00, b.
Observations and Findinas LER 50-336/97-10-00 described that the combined weight of the heavy dummy fuel assembly (HDFA) and its associated handling tool was 2015 pounds, which exceeds the Technical Specification (TS) 3.9.7 limit of 1800 lbs for movements of loads over irradiated fuelin the spent fuel pool. The cause of this condition was that the weight of the handling tool, which is 270 lbs, had never been taken into consideration. Movement of the HDFA over irradiated fuelis only necessary whenever the new fuel elevator is tested. The inspector verified that procedures EN 21046, " Spent Fuel Pool Platform Crane Pre-operational Checklist," and OP 2303B, "SFP Fuel Handling Operations," have been revised to add a special precaution to prohibit the movement of the HDFA over irradie. d fuel.
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Procedure 21047, "New Fuel Elevator Pre-operational Checklist" has been canceled. The licensee also has submitted a TS change request to make the HDFA an exception to the 1800 pound limit. This change is under evaluation by the NRC; but, it is not required for the restart of Unit 2.
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Conclusions The NRC concluded that the licensee has implemented acceptable corrective actions to procedurally prohibit future movement of the HDFA over irradiated fuel, which is in violation of the current TS 3.9.7 limiting condition for operation. Therefore, LER 50-336/97-10-00 is closed. Past movement of the HDt-A over irradiated fuel was in violation
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of TS 3.9.7. This non-repetitive, licensee-identified and corrected TS violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-336/98-05-01)
08.2 (Closed) 'JRI 50-336/97-203-04: Emeraencv and Abnormal Ooeratina Procedures i
Ucarade Proaram Status: (Closed - Unit 2 Sionificant item List No.10: Update -
Sianificant item List No. 8.41 a.
Insoection Scooe (92901/420011 The inspector reviewed the status of the Millstone Unit 2 emergency operating procedure (EOP) and abnormal operating procedure (AOP) upgrade programs which is subject of Millstone Unit 2 Significant item List (SIL) No.10. The inspection included: interviews; a review of applicable procedures and other documentation necessary for evaluation and determination of the program status; a review of a nuclear oversight audit report covering
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the EOP program conducted in April of 1998; and a review of Unresolved item (URl; oO.
336/97-203-04 which concerned the adequacy of procedural guidance for a loss of containment integrity.
b.
Observations and Findinas
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l Emeraencv Ooeratina Procedurm The licensee has deferred action on revising EOPs under their upgrade program post-startup
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j and continues to track the associated action items within their corrective action program.
l However, the licensee has identified specific issues from the EOP upgrade program that l
they consider necessary to support Unit 2 startup, or to address completion of various commitments prior to operational Mode 4 including:
l l
l The licensee has committed to revise the EOPs such that they continue to meet l
industry and NRC standards. Specifically, the licensee has completed the draft version of EOPs from an earlier upgrade effort consistent with Revision 3 of CEN-152, " Combustion Engineering Owners Group Emergency Operating Procedures Technical Guide." The licensee plans to conduct validation of the EOPs on the plant simulator, such that the EOPs will be available to support Unit 2 startup. While Revision 4 to CEN-152 is currently available to the industry, the licensee's efforts to revise the EOPs consistent with Revision 3 is considered satisfactory.
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NRC Inspection Report (IR) 50-336/97-203, addressed the licensee's commitment to evaluate and revise EOPs to address instrument setpoint uncertainties. Although
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the licensee is upgrading the EOPs consistent with CEN-152, Revision 3, one element of Revision 4 of CEN-152 that the licensee is incorporating into the EOPs l
prior to operational Mode 4 is the results of their instrument uncertainty study. This
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satisfactorily addresses the licensee's commitment.
i NRC IR 50-336/97-203 updated a previously identified NRC concern from a 1995
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inspection regarding the accuracy of 71 EOP support procedures. However, the licensee had identified these procedures following a comprehensive review of support procedures that needed revision prior to the scheduled startup during that time period. This issue is currently being tracked by the licensee with the appropriate revisions to the support procedures scheduled for completion prior to i
l operational Mode 4. The inspector considers the licensee's efforts to address the support procedures to be acceptable.
l Nuclear Oversight Audit Report MP-98-A06, dated June 15,1998, detailed the
l evaluation of the effectiveness of the EOP program. The inspector found the audit
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to be thorough and of high quality, in particular, one audit finding was that EOP 2534, " Steam Generator Tube Rupture," contained actions regarding system lineup for the removal of noncondensible racioactive gases that were inconsistent with specific assumptions of Chapter 14.6.3 of the Final Safety Analysis Report (FSAR),
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and outside the bounds of the accident analysis for radioactive effluent releases.
The licensee determined that this concern involved an unreviewed safety question, i
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The NRC is tracking resolution of the resulting licensee submittal dated November 13,1998.
Abnormal Ooeratina Procedures The licensee has deferred action on revising AOPs under their upgrade program post-startup and continues to track the associated action items within their corrective action program. However, the licensee has identified specific issues from the AOP upgrade program that they consider necessary to support Unit 2 startup. This includes the creation of AOPs associated with Appendix R (10 CFR 50). The NRC will review these AOPs as part of Millstone Unit 2 Significant items List No. 21.
In the previous NRC inspection of AOPs, URI 50-336/97-203-04 was opened due to concerns regarding the adequacy of procedural guidance for the loss of containment integrity. Specifically, Unit 2 Technical Specification 6.8.1.a requires that written procedures shall be established, implemented and maintained covering the activities recommended in Appendix "A" of Regulatory Guide (RG) 1.33, February,1978. RG 1.33, l
Appendix "A", Paragraph 6, recommends procedures for combating emergencies and other
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significant events, such as " Loss of Containment Integrity." Although the licensee was still considering creating i specific AOP for loss of containment integrity after restart, they believed that exist 3
,arocedures adequately satisfied the RG 1.33 requirement. These procedures are surs, lance procedure SP 2605A, " Verifying Containment integrity," and l
emergency operat procedure EOP 2540E " Functional Recovery of Containment
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l Integrity."
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The NRC inspector reviewed procedures SP 2605A and EOP 2540E and does not fully j
agree that these procedures satisfy the RG 1.33 requirement. Procedure SP 2605A is often the mechanism that problems with containment integrity are discovered, but is only
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performed monthly in Modes 1, 2,3, and 4 Procedure EOP 2540E also does not satisfy the RG 1.33 requirement. The entry condition for EOPs is a reactor trip and procedure EOP 2540E would bc performed only when specific safety function checks associated with containment integrity are not met. Therefore, this EOP is not intended to reflect the actions that would be taken with the plant in Modes 1,2,3, and 4 when containment integrity is required. However, further review by the inspector disclosed that a loss of containment integrity is not a self revealing event as would be the case for a cubatmospheric containment, thus not lending itself to an alarm response procedure. Any identified loss of containment integrity would prompt the operators to enter the appropriated technical specification for rernedial actions. The licensee is generating a general procedure to address the issue. The inspector determined that this matter constitutes a violation of minor significance and is not subject to formal enforcement l
action.
c.
ConclusiQns
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Following a review of the Unit 2 Emergency and Abnormal Operating Procedures revision process, the NRC concluded that overall, the licensee has appropriate measures established such that procedures necessary to support startup of Unit 2 will be ready for use by J
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j operators. Therefore, Significant items List No.10 is considered closed. One concern that was identified during this inspection was the failure to establish a procedure for a loss of containment integrity as required by TS 6.8.1 and RG 1.33. Additional review by the
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inspector determined this to be a minor violation. URI 50-336/97-203-04 is considered closed. To address this concern, the licensee has committed to develop an abnormal operating procedure for loss of containment integrity, and to perform a review of RG 1.33 to ensure the necessary procedures are in place such that compliance. with TS 6.8.1 and RG 1.33 is established.
U2.ll Maintenance U2 M1 Conduct of Maintenance i
M 1.1 General Maintenance Observations a.
Insoection Scooe (61726)
During routine plant inspection tours, the inspectors observed 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 interviewed licensee field personnel to verify the adequacy of work controls. The inspector observed all or part of activities i
performed under the following procedures:
l SP 2604A
"A" HPSI Pump Inservice Test
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l SP 2609E EBFS Negative Pressure Test
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The inspector observed performance of Section 4.4 of procedure SP2604A, which executes the "A" HPSI pump high flow inservice test. The inspectors found the testing was being performed in accordance with approved procedures. This test provides supplemental data in a different regime of pump operation from the regular inservice test, l
which uses the minimum flow recirculation line. This test was conducted to collect data L
for evaluation of pump performance following an overhaul. During the overhaul, the licensee identified that the pump casing was misaligned and corrected the alignment. The test results demonstrated that the pump was operating properly, and that the overhaul had significantly reduced pump vibration. The inspector found that the acceptance criteria had been established in a manner consistent with the licensee's approved inservice test program.
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The licensee conducted the enclosure building negative pressure test using procedure SP2609E to evaluate the integrity of the enclosure building and determine the scope of any
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necessary repair activities. The test involved starting the enclosure building filtration i
system and recording the internal pressure of the building as a function of time after the system start. The operations department personnel conducted a thorough briefing prior to
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the test and completed the testing without incident. However, the test results indicated that the enclosure building integrity was inadequate to achieve the necessary negative pressure and that repairs were necessary. The inspector found the system configuration established by the test procedure and the test acceptance criteria acceptable, c.
Conclusions The inspectors concluded that the HPSI pump high flow inservice test and the enclosure building negative pressure tests were thorough and satisfied the objectives of the activity.
The test procedures were adequate and included appropriate acceptance criteria.
M 1.2 Medium Voltaae Circuit Breaker Maintenance a.
Insoection Scooe (62707)
The inspector observed maintenance work on a safety-related medium voltage breaker and interviewed maintenance department personnel. The inspector also reviewed maintenance procedures and the licensee's circuit breaker maintenance program document.
b.
Observations and Findinas l
l The inspector observed a portion of the preventive maintenance performed under Automated Work Order (AWO) M2-98-08026 on the safety-related breaker located in l
Cubicle A410, which is the tie breaker between the safety-related 4160 Volt ac Bus 24D l
and the non-safety-related 4160 Volt ac Bus 248. This AWO specified performance of specific sections of maintenance procedure MP2720C3, "GE Model AM Magne-Blast Circuit Breaker Maintenance," which involved inspection, cleaning, measurement, adjustment, and testing of the breaker. The inspector interviewed the maintenance
personnel regarding the performance of the maintenance activities. The inspector found that the breaker maintenance activities were performed in accordance with procedure MP2720C3 and that the measurements and test results were checked against appropriate acceptance criteria.
The licensee had selected certain breakers for overhaul and other breakers for preventive maintenance. The inspector reviewed the licensee's circuit breaker maintenance program document and interviewed maintenance personnel to determine the criteria used for selection of the level of breaker maintenance. The inspector found that the breaker located in Cubicle A410 was appropriately selected for preventive maintenance in accordance with the program document and industry and vendor recommendations.
c.
Conclusions The NRC inspector concluded that the maintenance on the medium voltage breaker located in Cubicle A410 was performed in an acceptable manner using approved procedures. Also, the licensee had acceptable justification for the level of maintenance performed on individual breaker U2 M8 Miscellaneous Maintenance issues M 8.1 (Closed) LER 50-336/96-39-00 & (Ocen) eel 50-336/97-02-12: Inadeauate Surveillance Test for Containment Purae Svstem Containment Isolation Valves (Undate Unit 2 Sianificant Items List No. 8.6)
a.
Insoection Scooe (92700)
The inspector reviewed the licensee's corrective actions to address Licensee Event Report (LER) 50-336/96-39-00. This LER was one of 17 LERs associated with Escalated Enforcement item (EEI) 50-336/97-0?-12 which involved numerous examples of inadequate surveillance procedures. Although enfc cement discretion was exercised for this apparent violation, this eel, as well as Unit 2 Significant items List No. 8.6, will be characterized as open until each of the 17 LERs have been dispositioned by the NRC.
b.
Observations and Findinas LER 50-336/96-39 describes that procedure SP 2605H, " Containment Isolation Valve Operability Test-Shutdown," did not satisfy the requirements of Technical Specification (TS) 4.9.10. Procedure SP 2605H tested the closure function of the containment purge system containment isolation valves by tripping only one of the four bistables in the isolation actuation circuitry and observing the closure of purge valves. However, the procedure failed to test the circuitry from the containment radiation monitors to the bistables nor did it test the other three bistables.
In its corrective action for this LER, the licensee stated that (1) procedure SP 2605H would be revised to ensure that all bistables are tested; (2) the procedure would be re-performed; and that, (3) there would be a 100 percent review of the adequacy of all TS surveillance tests.
The inspector found that procedure SP 2605H had been adequately revised to address the stated concerns and that this test was re-performed using the updated test procedure with satisfactory data obtained. eel 50-336/97-02-12 was updated in NRC Inspection Report 50-336/97-212 which stated that the NRC verified that the licensee had performed a 100 percent review of all TS surveillance procedures versus the actual TS requirements and was in the process of correcting identified procedure deficiencies.
c.
Conclusions The licensee's corrective actions to address LER 50-336/96-39-00 were found to be acceptable and therefore, this LER is considered close. -
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M8.2 (Closed) LER 50-336/96-40-00 & (Ocen) eel 50-336/97-02-12: Inadeauate
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Surveillance Procedure for Verifvina Motor Circuit Breaker Position (Undate - Unit 2 Sianificant items List No. 8.61 a.
Insoection Scooe (92700)
i The inspector reviewed the licensee's corrective actions to address Licensee Event Report (LER) 50-336/96-40-00. This LER was one of 17 LERs associated with Escalated Enforcement item (EEI) 50-336/97-02-12 which involved numerous examples of inadequate surveillance procedures. Although enforcement discretion was exercised for this apparent violation, this eel, as well as Unit 2 Significant Items List No. 8.6, will be characterized as open until each of the 17 LERs have been dispositioned by the NRC.
b.
Observations and Findinas LER 50-336/96-40-00 described that procedure SP 2619A, " Control Room Shift Checks,"
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did not adequately satisfy the requirements of technical specifications for verifying motor i
circuit breaker positions. In certain plant conditions, for the charging pumps, high pressure safety injection pumps and the reactor coolant pumps, technical specifications require a verification every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that circuit breakers are disconnected from their power supply.
Because procedure SP 2619A is performed by operators in the control room, they did not directly verify that the circuit breakers were disconnected or " racked out." instead, operators verified that control board indicating lights were extinguished. In addition, the breakers were danger tagged in the disconnected position, j
During this inspection the inspector observed that the following operations surveillance forms have been revised to locally verify that appropriate breakers are in the open position:
OPS Form 2669A-1, " Unit 2 Turbine Building Rounds"
OPS Form 2669A-2, " Unit 2 Auxiliary Building Rounds"
OPS Form 2619A-3, " Control Room Daily Surveillance, Mode 5"
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OPS Form 2614A-2, " Control Room Daily Surveillance, Mode 6 or Defueled"
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OPS Form 2614A-3, " Weekly Checks in Modes 5 and 6 or Defueled"
l c.
Conclusions Based on the above review of corrective actions, LER 50-336/96-40-00 is closed.
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M8.3 (Closed) LER 50-336/97-03-00 & -01: (Ocen) eel 50-336/97-02-12: Historical Technical Soecification Noncomoliance of Plant Surveillance Procedure Used to Perform Periodic Insoection of Fire Protection System Smoke Detectors (Undate -
Unit 2 Sionificant items _ List No. 8.61 a.
Insoection Scoce (9270Q1 The inspector reviewed the licensee's corrective actions to address Licensee Event Report (LER) 50-336/97-03-00 & -01. This LER was one of 17 LERs associated with Escalated Enforcement Item (EEI) 50-336/97-02-12 which involved numerous examples of inadequate surveillance procedures. Although enforcement discretion was exercised for this apparent violation, this eel, as well as Unit 2 Significant items List No. 8.6, will be characterized as open until each of the 17 LERs have been dispositioned by the NRC.
b.
Observations and Findinas LER 50-336/97-03-00 & -01 noted that surveillance procedures for verifying the operability of smoke detectors located in certain areas of the plant did not conform to technical
specification tables. This is a historical non-compliance in that the fire protection requirements were removed from the Technical Specifications in November 1995 and placed in the Technical Requirements Manual (TRM). However, the procedure in use after November 1995, was still not in accordance with the TRM.
As corrective actions, plant procedures were revised to ensure compliance with the fire protection system requirements in the TRM for the smoke detectors in the Auxiliary Building West Piping Penetration Room and the Auxiliary Building General Area the -5 foot elevation. The inspector reviewed the following procedures and verified that they had been changed:
SP 2618C, " Fire Protection System Smoke Detector Test"
OPS Form 2618C-1, " Fire Protection System Smoke Detector Test"
SP 2618D, " Fire Protection System Sprinkler and Deluge Design Functional Test"
OPS Form 2618D-1, " Fire Protection System Sprinkler and Deluge Design Functional
Test" In addition, the inspector reviewed a sample of completed test data performed in 1997 showing satisfactory performance of the smoke detectors.
c.
Conclusions Based on the above review, LER 50-336/97-03-00 & -01 is considered close...
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t U2.lli Enaineerin.g
U2 E8 Miscellaneous Engineering issues i
E8.1 (Closed) eel 50-336/96-04-10: (Closed) Unresolved item 50-336/96-04-11:
Adeauaev of Reactor Buildino Closed Coolina Water Svstem Flow Rates (Closed -
Unit 2 Sianificant items List No. 39.D i
a.
Insoection Scone (92903)
The inspector reviewed Escalated Enforcement item (eel) 50-336/96-04-10 and Unresolved item (URI) 50-336/96-04-11, which involve the adequacy of reactor building closed cooling water (RBCCW) system flow to various safety-related components. The unresolved item was opened pending the validation of RBCCW design parameters, issuance of any revised analyses resulting from changes in design parameters, and establishment of satisf actory as-j left RBCCW flow rates. This inspection involved interviews with operations department
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and engineering department personnel, as well as a review of engineering documents and calculations associated with the RBCCW system.
b.
Observations and Findinas The issues associated with URI 50-336/96-04-11 included the following specific concerns:
(1)
the licensee identified that the value used in the containment temperature analysis for the RBCCW flow through each of the shutdown cooling heat exchangers was inconsistent with the value specified in the RBCCW process flow diagrams (drawings 25203-26056 and 25203-26070 for the "A" and"B" RBCCW headers, respectively) and the actual flow rate established in the RBCCW system during flow balancing;
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(2)
the RBCCW system temperatures specified in the following documents were not consistent: the containment temperature analysis, the RBCCW process flow diagram, and Table 6.3-4, Table 6.5-2, and Section 9.4.3.2 of the Final Safety
' Analysis Report (FSAR); and (3)
the RBCCW flow rates assumed in the containment temperature analysis did not include a margin above the flow rate established during flow testing to account for instrument inaccuracy.
As described in NRC Inspection Report 50-336/96-04, the licensee repeated the analysis using the correct RBCCW flow to the shutdown cooling heat exchanger and subsequently documented the error in Adverse Condition Report (ACR) 8344. However, this ACR was closed without identifying the cause of the error and without evaluating the accuracy o'
other assumptions used in the containment temperature analysis. This apparent violation of requirements to take corrective actions to prevent recurrence was documented as eel 50-336/96-04-1 ~.. -
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The licensee's root cause evaluation initiated in response to this eel attributed the error to the lack of controls or guidance provided for design inputs used in calculations. The corrective actions to address the broader design control process concern includes the licensee's Configuration Management Program review of design basis information, including assumptions used in calculations, and associated changes to the design control process to maintain design basis information. Programmatic concerns associated with design control, which have been associated with other NRC escalated enforcement actions at Millstone Unit 2, are within the scope of NRC review through its independent corrective action verification program oversight function, and NRC conclusions developed through performance of that function will be documented in separate reports.
To address the specific RBCCW system technical concerns associated with the eel and URI 50-336/96-04-11, the licensee initiated a process to establish new design basis RBCCW system flow rates compatible with the system's capability. This action was necessary because early flow balance calculations demonstrated that the original design flow for the shutdown cooling heat exchanger during the recirculation phase after a loss of coolant accident (LOCA) would divert flow from the containment air recirculation (CAR) coolers to such an extent that design flow to the CAR coolers would not be maintained. This condition existed because RBCCW flow to the shutdown cooling heat exchanger is designed to initiate at the start of the post-LOCA recirculation phase, and because the original design RBCCW flow rate to the shutdown cooling heat exchanger was about half of the total RBCCW header flow rate. To correct this condition, the licensee reanalyzed the RBCCW system using much lower design flow rates to the shutdown cooling heat
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exchanger and CAR coolers in the post-LOCA recirculation phase such that the total flow
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l was within system capability.
l The revised RBCCW design flow rates for the shutdown cooling heat exchangers and the l
CAR coolers were used in revised calculations to evaluate containment pressure and
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temperature response to a large-break LOCA and a main steam line break. The computer model used for this evaluation included a detailed model of the RBCCW system, which addressed concerns regarding RBCCW temperature at the inlet to the CAR coolers by calculating the time-dependent RBCCW temperature at the inlet to the CAR coolers and by using that value to determine containment heat removal through the CAR coolers. The same model was used to calculate the post-accident peak RBCCW temperature, but the assumptions were changed in order to maximize RBCCW temperature rather than containment pressure. These evaluations indicated that RBCCW system performance at the revised flow rates was adequate to maintain post-accident containment pressure and peak RBCCW temperature within design limits.
l The licensee developed a computer flow model of the RBCCW system to establish l
acceptance criteria for actual system flow rates that included margin for pump uegradation j
and instrument error. The instrument error margin was provided by adding a margin to the design flow equal to 2 percent of the full scale of the flow instrument for non-safety-
related components and 5 percent of peak post-accident flow for safety-related components. The margin for pump degradation was computed by balancing the system
model at the design flow rates plus the margin for instrument error using the degraded pump performance characteristics and then determining the component flows in the same
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system model configuration using the nominal pump performance characteristics. The component flows calculated by the model using the nominal pump performance characteristics were then flow values that incorporated margin above design values for pump degradation and instrument error.
The licensee implemented special procedure SPROC 97-2-19, " Reactor Building Closed Cooling Water System Flow Balance," to set actual RBCCW flow to each component at values that included margin for instrument error and pump degradation. The valve positions associated with these flow rates were recorded for use as required throttled positions. An engineering evaluation of the as-left RBCCW flow rates documented that design basis flow rates for safety-related components were satisfied with margin for instrument error and pump degradation. The inspector found this evaluation acceptable.
Following the performance of the procedure SPROC 97-2-19, the licensee changed form 2611C-2, "RBCCW System Alignment Checks, Facility 1," and form 2611D-2, "RBCCW System Alignment Checks, Facility 2," to specify the valve positions established during the performance of procedure SPROC 97-2-19 as the required positions. The inspector found that the required valve throttle positions were correctly translated to the valve alignment forms.
By integrating information from the various RBCCW system evaluations, the licensee revised the RBCCW process flow diagrams (drawings 25203-26056 and 25203-26070).
For each operating condition (i.e., normal power operation, shutdown cooling operation, or post-accident operation), the diagrams provide the flow rate, pressure, and temperature at l
various system locations. The inspector found the information for these parameters contained in the process flow diagram to be consistent and representative of design basis operating conditions.
The licensee implemented FSAR changes to correct discrepancies in the FSAR regarding l
the RBCCW system. Table 6.3-4 of ;he FSAR was deleted because it contained redundant and inaccurate information. Table 6.5-2 of the FSAR contains nominal design information for the CAR coolers and is not discrepant. Changes to Section 9.4.3 of the FSAR have been approved to reflect correct information regarding post-accident operation of the RBCCW system. The inspector found that these FSAR changes adequately addressed the concerns with FSAR accuracy associated with URI 50-336/96-04-11.
Both NRC Inspection Report 50-336/98-202 and Section M2 03.1 of this current inspection report discuss the failure of the licensee to adequately translate RBCCW system design information into testing and operating procedures. The NRC is addressinq these concerns separately from URI 50-336/96-04-11 and eel 50-336/96-04-10, whicn focus on i
l the failure to establish an adequate design basis for the RBCCW system.
c.
Conclusions The NRC concluded that the licensee effectively addressed the specific concerns I
associated with URI 50-336/96-04-11 and eel 50-336/96-04-10, which involved the j
adequacy of RBCCW system flow to various safety-related components. The NRC found
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4 that the mo?eling, calculations, and testing that were performed acceptably demonstrated
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the design adequacy of the revised RBCCW flow provided to safety-related components.
Therefore, eel 50-336/96-04-10, Unresolved item 50-336/96-04-11, and Unit 2 Significant items List No.39.1 are closed.
E8.2 ICJosed) Unresolved Item 50-336/96-201-38: Failur,lo Consider Post Accident Fluid
.Tamneratures in Analvses: (Closed - Unit 2 Sianificant items List No. 39.2)
a.
Insoection Scooe (92903)
NRC Inspection Report 50-336/96-201 discussed the potential for flow choking in the high pressure safety injection (HPSI) system. Flow choking could occur at components that provide significant pressure breakdowns, such as the flow orifices in each HPSI injection leg. Since the system draws water at elevated temperatures (250 F) from the containment sump under post-accident recirculation conditions, the potential for choking and the effects of choking in that system increases. The failure of the licensee to calculate available system flow rates utilizing the higher fluid temperatures predicted for post-accident conditions was considered to be unresolved item, URI 50-336/96-201-38, pending licensee O
completion of its HPSI flow evaluation and NRC review.
b.
Observations and Findinas The inspector reviewed Calculation 97-074, Rev. O,11/20/97, which contained the thermal hydraulic analysis of the HPSI and LPSI systems. This calculation specifically analyzed for cavitation: the eight HPSI throttling valves to the reactor coolant system (2-SI-617, 616, 627,626,637,636,647 and 646) and the eight pressure breakdown orifices, FO-3693 to FO-3700, which are located just downstream of the HPSI throttling valves. In the licensee's Calculation 97-122, Rev. 2,8/5/98, the thermal hydraulic model results developed from Calculation 97-074 Rev. O, updated to PROTO-FLO" Version 4.01, were used as input to the Unit 2 accident analyses for the adequacy of the net positive suction head for the HPSI and LPSI systems and for the evaluation of the potential'or cavitation in the HPSI throttle valves and flow orifices. This revision of the calculation compared the ECCS PROTO-FLO" Version 3.04 model with actual test data to verify the full open valve coefficient, Cv, of the HPSI throttle valves. The HPSI throttle valve flow curves were revised and the possibility of cavitation in the throttle valves was re-evaluated.
Three basic configurations of the emergency core cooling system (ECCS) were analyzed:
(1) hjection mode with suction from the refueling water storage tank (RWST); (2)
recirculation mode with suction from the containment sump; and (3) the boron precipitation control, recirculation mode with water from the containment sump directed either to the hot leg of the reactor coolant system (RCS) or to the pressurizer. Subcases were developed to
represent: (a) pump status and condition (degraded vs. design); (b) maximum and minimum
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positions of the HPSI injection throttle valves and the LPSI flow control valve (i.e., valve 2-I SI-306, the bypass valvc for the shutdown cooling heat exchanger); * boundary conditions which included pressures and temperatures in the RWST, the containment sump, and the RCS; (d) containment spray pump flow rates; (e) component f ailures (i.e., diesel or pump failure); and (f) system flow paths. In June 1998, the licensee conducted flow testing of
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the ECCS and used the test results to determine the valve coefficients, Cv, for the HPSI throttle valves.
The inspector performed a sample walkdown of the piping for the HPSl pumps, throttle valves and flow restriction orifices for comparison to the isometrics which were used as input to Calculation 97-074. No problems were identified.
The inspector also reviewed key assumptions associated with the calculations and had one concern. For the recirculation phase, a maximum containment sump water temperature of 212 F was assumed which is in contrast to the 250*F sump water temperature mentioned in NRC Inspection Report 50-336/96-201 and in the Unit 2 Final Safety Analysis Report, Section 6.4.4.1, which states that "The peak calculated containment pressure is 51.2 psig with 250*F sump water and 14.7 psig with 92*F sump water." The inspector discussed the concern with the licensee who revised Calculation 97-122 to clarify that the 250 F sump water temperature occurs during the injection phase. The maximum sump temperature in the recirculation phase is 182.63 F but the calculation conservatively used 212"F, the saturation temperature with the containment at atmospheric pressure. The inspector found this clarification to be acceptable.
The results of the Calculation 97-122 showed that at minimum flow conditions, that is, l
when the HPSI throttle valves are highly throttled and the RWST and the containment sump
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are at their lowest possible levels and the HPSI pumps are degrader incipient cavitation is indicated at the throttle valves. NUREG/CR-6031, " Cavitation Guide for Control Valves,"
describes incipient cavitation as the lowest level of cavitation intensity and the only
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consequence is a barely audible flow noise. The licensee concluded that the level of
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cavitation is below that associated with damage and therefore is not a concern for continued operation of the ECCS. The inspector considered this conclusion for the throttle valves acceptable.
The results of the Calculatio:1 97-122 indicated that for the worst case condition of high flow rate and high differential pressure across the HPSI flow restriction orifices (FO-3693 to 3700), choked flow is imminent in the restriction orifices as conditions approach atmospheric pressure in both the RCS and the containment. The inspector was concerned that the calculation did not provide any addition discussion regarding why the " imminent" i
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choked flow was acceptable. The licensee clarified the calculation conclusion to state that the choked flow condition occurs in one specific alignment for boron precipitation control when a Facility 1 failure occurs prior to cafety injection. In this case, the calculation demonstrates that the choked flow in the orifices would reduce HPSI flow by only 2 gpm 007 gpm to 205 gpm). The licensee also showed that the flow models developed from O.lculation 97-122 were used as an input into Design Change Request M2-98074, "Long-l Term Cooling (Post-LOCA)," which showed that the required HPSI flow in this case is 180 l
gpm. The inspector found the clarification to the calculation to be acceptable, c.
Conclusions
The licensee's calculations and conclusions concerning possible cavitation and choked flow in the HPSI flow restriction orifices and throttling valves in response to URI 50-336/96-201-
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38 were acceptable. No violations were identified. URI 50-336/96-201-38 and Unit 2 Significant items List No. 39.2 are considered closed.
E8.3 (Uodate) eel 50-336/96-201-42 & 43: Material. Eauioment and Parts List Proaram (Uodate - Unit 2 Significant items List No.18)
a.
Insoection Scooe (93903)
This inspection involved a review of the licensee's self-assessment PES-SA-98-101, "MP2 Material, Equipment, and Parts List (MEPL) Process." Concerns with the MEPL process are the subject of Escalated Enforcement items (Eels) 50-336/96-201-42 & 43 which are currently open and are considered restart issues.
b.
.Qhtervations and Findinas i
The inspector found that the licensee's MEPL self-assessment to be of high quality and self-
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critica!, particularly regarding the disposition of MEPL-related non-conformance reports (NCRs). The self-assessment noted that the previous self-assessment in December 1997 stated that the NCRs for MEPL upgrades provided minimal justification for the "use as is" disposition of components / parts installed in the field. The recent self-assessment states that procedural enhancements designed to address these issues were not effectively implemented, inferring a lack of management attention and failure to establish and enforce high standards.
The findings of the licensee's self-assessment are consistent with NRC inspection reports.
Cver the past two years, the inadequate disposition of MEPL-related NCRs has been documented in several NRC inspection reports and was the subject of eel 50-336/96-201-l 43. This concern was updated in NRC IR 50-336/97-208 and was again discussed in NRC IR 50-336/98-207, which described the site-wide corrective actions to address inadequate MEPL-related NCRs that were taken as a result of Unit 3 Violation 50-423/98-207-15.
c.
Conclusion
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The NRC found that the !lcensee's MEPL self-assessment to be of high quality and very self-critical, particularly regarding the disposition of MEPL-related NCRs. The licensee's previous self-assessment, as well as several NRC inspection reports over the past two years, have l
discussed the inadequate justification for the "use as is" disposition for MEPL upgrades.
i The NRC is concerned that at this point in the recovery process, licensee management has not been effective in addressing this concern. Accordingly, eel 50-336/96-201-42 & 43, as l
well as Unit 2 Significant items List No.18, remain open.
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E8.4 (Closed) LER 50-333/97-005-00: Inservice Test Instrumentation Does Not Meet ANSI /ASME Chaoter XI Reauirements: (Closed - Unit 2 Sionificant items List No.
49.2)
a.
Insoection Scoce (92700)
The inspector reviewed the licensee's corrective actions associated with Licensee Event Report (LER) 50-336/97-005-00. The LER involved three deficiencies where instrument calibration requirements imposed by the American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code,Section XI, were not met. The inspection included interviews, evaluation of licensee response in accordance with 10 CFR 50.73, as well the review of applicable procedures and other documentation.
b.
Observations and Findinas Technical Specification (TS) 4.0.5 establishes the requirement that in-service testing (IST) of ASME Code Class 1,2 and 3 pumps shall be performed in accordance with Section XI of the ASME Code as required by 10 CFR 50.55a. The licensee generated LER 50-336/97-05 as a j
condition prohibited by TSs, whRh documented three IST deficiencies:
High Pressure Safety injection (HPSI) pump flow had been measured with a digital
instrument with an accuracy outside the calibrated range of the instrument.
Service Water pump suction pressure had been obtained with the use of a
differential level instrument, where the full range of the instrument was greater than three times the instrument reference value.
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Low Pressure Safety Injection (LPSI) pump differential pressure had been obtained
with the suction and discharge pressures determined from plant process computer points which were not included in the licensee's calibration program.
The corrective actions that were taken to address the specific deficiencies included: (1)
The HPSI pump instruments were calibrated within the 12% requirement and modification was performed that permanently installed digital instruments where temporary instruments had previously been utilized; (2) Deleted the use of the traveling water screen differential pressure correction in the service water pump suction pressure calculation. Procedure changes were implemented that supported both the deletion of the correction, as well as the use of a new level indicator used in the determination of the suction pressure. (3)
Temporary gages with appropriate calibration controls are now used in support of LPSI pump IST in lieu of the suction and discharge pressures determined from plant process computer points.
Broader corrective actions that were taken included: (1) Developed the IST Program Manual which provides instructions to both administer and monitor the IST program, and provides for adequate supervisory review of program implementation; (2) Developed procedure IC 2438, " Preventive Maintenance Program," which details the identification, calibration, and maintenance of installed instrumentation used in support of safety-related equipment; (3)
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Developed an IST instrumentation database that identifies all instruments used to support the instrument and control (l&C) calibration program; (4) Performed an engineering evaluation on instruments used in support of IST pump testing such that acceptability for use was documented and ASME Section XI requirements were met, c.
Conclusions The licensee's corrective actions have adequately addressed LER 50-336/97-05-00, which involved three deficiencies where instrument calibration requirctnents imposed by the ASME Boiler and Pressure Vessel Code,Section XI, were not met. This non-repetitive, licensee-identified and corrected violation is being treated as a Non Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. LER 50-336/97-005-00 and Unit 2 Significant Items List No. 49.2 are considered closed. (NCV 50 336/98-05-02)
E8.5 (Closed) LER 50-336/97-033-00 & 01: Desian Deficiencies with Enaineered Safeauards Actuation Svstem Power Sucolies and Fuses (Closed - Unit 2 Sianificant items List No. 521 a.
Insoection Scoce (92903)
The inspector reviewed the licensee's disposition of Licensee Event Report (LER) 50-336/97-033. Revision 0 of this LER described that the engineered safeguards actuation system (ESAS) was inoperable because the power supply fuses in the Facility 1 and 2 actuation cabinets could have blown if an ESAS actuation were to occur, thereby preventing the actuation safety equipment. Revision 1 of this LER described that additional testing showed that an ESAS actuation would not have caused the fuses to open. The inspector observed the performance of the test procedures and reviewed the engineering evaluation that provided the licensee's basis for determining that this potentially safety significant issue was no longer a concern.
b.
Observations and Findinas l
On July 27,1997, a 6 Amp fuse opened in the power supply drawer for ESAS actuation cabinet 5 (Facility 1). At the time the fuse opened, no plant transients or off-normal evolutions were in progress. The power supply powers 17 actuation modules associated with the safety injection actuation signal (SIAS), which starts vaiious safety-related equipment, and the undervoltage signal, which starts the emergency diesel generators. No
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l fault or short condition was found in the actuation cabinet that would have caused the fuse i
to open.
l The initial testing to determine the cause of the blown fuse involved replacing the blown fuse and determining the current through the fuse using the power supply drawer's built in i
test jacks. The measured current through the 6 Amp fuse was 5.2 Amps with the ESAS actuation cabinet in a non-actuated state. Since the 17 actuation modules energize to actuate the safety equipment, the current draw with ESAS cabinet in an actuated state is greater than in the non-actuated state. Although they did not measure the current draw with ESAS in the actuated state at this time, they determined that the additional current i
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1 draw would exceed the actual rating of the fuse. Another factor the licensee considered was that although the fuse is rated for 6 Amps, the fuse must be de-rated to 5.1 Amps because the ambient temperature inside the actuation cabinet heats the fuse and causes it to open at a lower current. The licensee submitted Revision 0 to LER 50-336/97-33 when they determined that there was no longer reasonable assurance that the ESAS actuation cabinet power supplies were operable due to the potential for simultaneous fuse f ailures in
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the Facility 1 and 2 ESAS.
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f Af ter submitting Revision 0 of this LER, additional testing showed that using the power l
supply drawer's built in test jacks to determino current was imprecise and led to incorrect
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conclusion regarding the cause of the blown fuse. The test jacks are used to measure the voltage drop across a 0.1 Ohm shunt resistor that is on the output from each power supply.
The current is determined by dividing the voltage drop value by the shunt resistance value.
l The licensee used the nominal shunt resistance value of 0.1 Ohms to initially determine that the non-actuated ESAS current was 5.2 Amps.
i AdditW current measurements were recorded using special procedure SPROC 97-2-15 and procedure IC 2430H, "8N65-1 Power Supply Drawer Current Shunt Calibration Check."
l Procedure IC 2430H :nvolved removing power supply drawer from the ESAS actuation cabinet and placing an in-line ammeter in series with a variety of load resistors that are placed on the output of the power supply. The voltage drop across the built in shunt resistor was also measured. The test results showed that the current measurement from the in-line ammeter was consistently less than current value derived using the shunt resistor. Based on this, the licensee determined the cause of this discrepancy was that the effective resistance of the shunt resistor was actually greater than 0.1 Ohms. Therefore, the power supply current was actually less than the 5.2 Amps they originally calculated.
Additional testing of the EE W cabinets in various states of actuation showed that the non-actuated current draw was 3.8 Amps, not 5.2 Amps, and that the actuated current draw was 4.4 Amps, which is less than the 5.1 Amp de-rated value of the fuse. Based on this, the licensee submitted Revision 1 to this LER which stated that the fuses and power supplies were adequately sized and that the blown fuse was most likely a random failure.
Accordingly, the LER stated that condition was not reportable.
LER 50-336/97-33 also discusses that the ESAS automatic test inserter (ATI) resulted in current spikes of 7.8 Amps. The licensee determined that 7.8 Amp value was in error because the strip-chart recording that was used could not accurately measure spikes that were only 2 milliseconds in duration. Additional measurements using procedure SP 97-2-15 showed that the worst-case current load with ATI operating was 4.4 Amps, c.
Conclusion The NRC determined that the licensee's disposition of LER 50-336/97-33 was acceptable.
Revision O o' this LER described that ESAS was inoperable because the power supply fuses in the Facility 1 and 2 actuation cabinets could have blown if an ESAS actuation were to occur, thereby preventing the actuation safety equipment. Revision 1 of this LER described that additional testing showed that an ESAS actuation would not have caused the fuses to j
open. The NRC determined that the licensee's basis for determining that this potentially l
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safety significant issue was no longer a concern was adequately supported. LER 50-336/97-33-00 & -01 and Unit 2 Significant items List No. 52 are considered closed.
E8.6 (Closed) Unresolved item 50-336/96-06-09 Reactor Core Thermal Power Level Exceeds License Limit a.
Insoection Scoce This item concerned steam generator (SG) blowdown flow inaccuracies and their impact on the plant calorimetric calculation. Licensee Event Report 95-43, associated condition reports, blowdown flow calculations and applicable procedures were reviewed and discussed with licensee personnel.
b.
Observations and Findinos Backaround Core thermal power is calculated by the plant process computer calorimetric program. The computer calculates the heat transfer rate from the reactor coolant system to the steam generators, and accounts for other heat additions and heat losses. Steam generator blowdown is a heat loss parameter which is accounted for to optimize plant electric output.
If estimated blowdown is greater than actual, then the calculated steam flow will be lower than actual, as steam flow is equal to feedwater flow minus blowdown. Thus, an overestimation of blowdown conditions will lead to non-conservative core thermal power estimates. This was the case on November 15,1995 when core thermal power exceeded the maximum licensed power level (2700 megawatts thermal), for an approximate 11 hour1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> duration.
To set up the desired blowdown flows, operators utilized valve curves given in procedure OP 2316A, " Main Steam System". These curves give a correlation of expected flowrates versus handwheel turns. Each steam generator has three parallellines from which the blowdown fluid enters a blowdown tank. Two of the lines have a large (2.5 inch) Blow-Off valve which is not designed for throttling. The third line has a small (1.0 inch) hy-drop throttle valve, which is designed for a specified primary throttling range (15 to 33 gpm) and a " blast" range (33 to 90 gpm). All three of the valves have mechanicallinkage of reach-rods connected to the handwheels as they are not readily accessible.
Blowdown Flow Desian Valve curves which defined the flow-handwheel correlations had been developed in 1984 during blowdown testing. A 1984 calculation (2-EN-106) developed these curves from tests conducted at several different valve positions. Essentially the effect on the plant calorimetric was determined against a baseline of zero blowdown flow to develop the handwheel-flow relationship. The inspector noted that this was required as flow process instrumentation was not part of the system desig _
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The inspector found that the inherent inaccuracies with this method, at certain valve l
positions, were extremely large. Ultrasonic flow measurements obtained in February 1996,
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indicated that errors between measured and predicted blowdown flow rates (for a given valve handwheel position), were as high as 50.7% and 97.3% for steam generators one and two, respectively. Errors were flowrate dependent, with underpredictions of flow occurring at lower flow rates and overpredictions at higher rates. The inspector noted that many factors contribute to the magnitude of the errors such as reach rod linkage wear (valve handwheels are not readily accessible), non-repeatability of valve positioning, and gradualinternal wear of the valve disc. The impreciseness of the developed curves
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resulted in exceeding the licensed rated core thermal power limit on November 15,1995.
Core Thermal Power Level Exceeds License Limit. November 15.1995 A contributing factor to this event was that feedwater chemistry had degraded after a long unit outage, resulting in the need for increased blowdown flow rates (138 gpm versus 50 gpm). At higher flow rates the valve curves overpredicted actual blowdown flows. The f'ow error created by operating in the higher flow regime of the curve was estimated to be approximately 48 gallons per minute (overestimate of flow) as the small blowdown valve design, limits flow to a nominal 90 gpm. The affect of the inaccurate valve curve, resulted in an inadvertent steady-state power level of 2709 MWth or a nominal 100.33% power for 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />. Although the licensed power level was exceeded, the inspector determined that the safety significance of the event was low in that at no time did power exceed the accident analysis assumption of 102% of rated power. In addition core thermal safety limits were not exceeded during the event.
Corrective actions consisted of a revision to procedure OP 2316A to ensure that a value of zero blowdown flow is input to the plant computer calorimetric program, regardless of actual flow conditions. The inspector found this action to be conservative as the plant computer will now over-estimate core thermal power. The core heat balance procedure, EN 21002, also was revised to further alert personnel to set blowdown flow to zero. This licensee identified and corrected violation of the licensed maximum power level, is being treated as a non cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Poncv. NCV 50-336/98-05-03 Extent of Condition Adverse condition report #5595 was initiated in response to the overpower event and documented the determination that no other areas or systems could be affected. The inspector, however, noted that blowdown flow rates are utilized in other areas, such as steam generator primary-to-secondary leak rate calculations. Technical Specification 3/4.4.6, " Reactor Coolant System Leakage", states that steam generator tube leakage is limited to.10 gallons per minute (144 gallons per day). The basis is to assure structural integrity of the leaking component such that totalleakage under accident conditions would remain below accident analysis assumptions of 1 gpm. The inspector noted that procedure l
SP2833, revision 9, " Secondary Coolant analysis for primary-to-secondary leak rate and l
dose equivalent iodine concentration," outlined several methods available to calculate primary-to secondary leak rates. Two of the methods described, tritium analysis and i
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monitoring of soluble nuclides in steam generator bulk water, had calculations which used steam generator blowdown flowrates. Thus, blowdown estimation errors had a direct impact on historical calculated leak rates.
To address historical operability and reportability, the licensee determined the errors between measured and predicted (valve curve) flow rates from field test data taken in February of 1996. This permitted the determination of any adjustments required for historical primary-to-secondary leakrate results. The inspector agreed with the licensee's conclusion that the condition was not reportable because the re-calculated historical leakage rates did not exceed Technical Specification 3/4.4.6.2, " Reactor Coolant System Leakage" requirements. Revision 10 of procedure SP 2833 was approved on April 23, 1998. The inspector noted that the primary to secondary coolant leak rate program outlined in this procedure was diversified in that several methods were provided to calculate leak rates, along with their limitations and advantages. For methods which utilized blowdown flowrate as an input, the licensee selected blowdown multiplication iactors of 1.5 and 2.0. These f actors were developed using engineering judgment, and will be automatically applied within the chemistry computer programs.
To independently validate the numbers, the inspector reviewed historical blowdown data, ultrasonic flow tests performed in 1996, and calculations of flow curves. The inspector confirmed that the factor of 2.0 for the large 2.5 inch valves was justified, based on 1990 test results and an underestimation of flow event in August of 1995. However, the 1.5 f actor for the small valves was not supported by plant testing results referenced in 1984 calculation 2EN-106, or more recent field testing via ultrasonic blowdown flow
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measurements in February of 1996. The inspector noted that the worst case flow I
estimation error existed at 5 handwheel turns open on steam generator #2 (estimated 24 gpm). The corresponding error between predicted flow from the new valve curve calculation, approved on April 14,1997, and measured flow from test data was 121 %.
The inspector recognized that the measured flow data was produced with degraded valves in 1996 and new valves installed this outage would result in reduced flowrates for a given handwheel turn. Nevertheless, the inspector determined that the 1.5 factor or an estimate of a 50% worst case error was not adequately supported, given the available data.
l The licensee stated that they plan to utilize ultrasonic flow measurements to benchmark l
and validate the new valve curve found in attachment 2 of operating procedure OP2316A.
l Additionally, scoping funds had been approved for evaluation of installing permanent blowdown flow instrumentation. The issue of blowdown flow estimation errors and their impact on steam generator primary-to-secondary leak rate calculations, requires inspector follow-up to ensure calculations adequately determine that reactor coolant system leakage technical specification requirements are satisfied. (IFl 50-336/98-05-04)
i c.
Conclusion Reactor core thermal power exceeded the licensed limit briefly by as much as 0.33% on one occasion due to inaccurate estimates of steam generator blowdown flowrate. The lack of permanently installed blowdown flow instrumentation has caused imprecise reactor power level and primary-to-secondary leak rato calculations. The licensee's original 1995
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extent of condition review was inadequate in that it did not more broadly consider the effect on primary to secondary leak rate determinations. The licensee has allocated resources to investigate installation of permanent blowdown flowrate instrumentation.
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l Reoort Detaila Summarv of Unit 3 Status Unit 3 began the inspection period on October 6,1998 at 100 percent power. When feedwater heater level control problems were identified on October 9, operators reduced power to 84 percent to facilitate troubleshooting. After the required level control valve repair, power was restored to 90 percent on October 11, and 100 percent on October 15 following another downpower to 85 percent to perform additional repairs to a thermowell and level controller.
On October 28, ope.ators manually tripped the reactor from 100 percent power, in accordance with abnormal operating procedures when high conductivity at the discharge of the condensate pumps was detected. Operators maintained the plant in hot shutdown (Mode 3) while the cause of the high conductivity was investigated. (See Section 01.1 for a discussion of the event.) After the affected waterbox was identified, operators took the reactor critical at 14:22 on October 30. During the power ascension secondary plant water hammers were experienced. After an engineering walkdown and plant maintenance were
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completed, power was restored to approximately 100 percent on November 9.
Operators again manually tripped the reactor, from approximately 90 percent, on November 11 due to an anticipated turbine trip / reactor trip due to degradation of condenser vacuum.
A problem with condenser vacuum was anticipated when, while backwashing one of the three condenser bays during a storm with one of the two affected circulating water pumps secured, the second circulating water pump tripped due to high differential pressure. (See Section 01.2.) Operators again took the reactor critical at 22:44 on November 12 and increased power to 100 percent on November 16. The unit remained at 100 percent through the rest of the inspection period, which ended on November 23.
U3.1 Ooerations U3 01 Conduct of Operations 01.1 Manual Reactor Trio on Hiah Conductivity Resultina From Leakina Condenser Tube a.
Insoection Scoce (71707)
On October 28,1998, oparators tripped the reactor from 100 percent power, in accordance with the abnormal operating procedure (AOP) for a condenser tube leak, due to high conductivity readings at the discharge of the condensate pumps. The inspector was informed of the event and responded to the control room and verified actions were taken in accordance with procedures and all systems functioned as required. The inspector attended severalinterdisciplinary licensee meetings, discussed corrective actions with plant personnel, and verified specific corrective actions were complete prior to restart on October 30.
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Observations and Findinos a
i Upon receipt of a high conductivity alarm, operators entered AOP 3557, Secondary
Chemistry. Operators entered AOP 3558, Condenser Tube Leak, as directed by AOP 3557, j
and manually tripped the reactor as required by the procedure. The inspector observed proper operator control of the plant following the trip. Operators placed and maintained the
plant in hot shutdown, Mode 3, in a controlled manner, in accordance with operations
procedures. The Unit Supervisor provided appropriate direction to reactor operators to j
control plant parameters within given bands. The inspector also noted proper control of i
management and extra operations personnelin the control room. Additional operators were
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assigned administrative tasks so that board operators could maintain focused on the plant.
j Proper operator self and peer checking was also observed.
After the reactor was shut down, the licensee commenced a methodical, sequential inspection of the condenser waterboxes. A leaking condenser tube was detected and
plugged on the third waterbox inspected. The leak was minor at the time of the trip, and was being handled by the condensate polishing facility to restore conductivity to normal
levels before entering the steam generators.
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Close coordination and communication was observed among operations, chemistry, engineering and maintenance departments. In addition, the management convened several
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times to discuss the event, progress made with troubleshooting, and corrective actions prior to restarting the reactor. The licensee decided to revise the AOP prior to restarting the reactor. The AOP revision may have prevented the reactor trip by allowing operators to determine the extent of salt water intrusion, based on chemistry information, before
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commencing a controlled plant shut down, if required. This revision had been identified as a
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corrective action after a September 15 trip, which also involved high conductivity at the j
i condensate pumps' discharge, and was to be completed in December.
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The October 28 reactor trip was similar to a September 15,1998 manual reactor trip in that the safety significance was low, no radiological releases were made, and the steam generators were protected. Although the unrevised AOP required the operators to act in a conservative direction and trip the plant, had the AOP been revised operators and sMety systems may not have been challenged with a potential transient.
The plant is designed to be able to operate, with less efficiency, with three of six waterboxes in service. Therefore, operation with waterboxes out to identify the leak would have been possible. Licensee management and PORC initially decided not to start up the l
plant without identifying the leak. After the first two waterbox inspections yielded no I
identified leaks, plant management discussed the potential need to start up the reactor in order to identify the leak. This option was thoroughly discussed and management decided this could be an option. The "C" waterbox was isolated and based on chemistry results
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appeared to be the problem. Management decided to restart the reactor while performing
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the specific leaking inspection in parallel. The inspector considered this management decision to be conservative since they had performed methodicalinspections of the previous
two waterboxes and the decision to commence restart was based on industry experience l
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The inspector verified that the AOP was revised and the leaking waterbox was identified, based on chemistry results, prior to restart. AOPs 3557 and 3558 were combined into AOP 3557. The specific, leaking "C" condenser tube was identified and plugged shortly af ter restart.
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Conclusions Unit 3 operators properly responded to high conductivity levels in the secondary system and
l manually tripped the reactor on October 28. Operators took appropriate command and l
control of the plant to place it in a safe condition in accordance with procedures. Close coordination and communication was observed among operations, chemistry, engineering
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and maintenance departments during the shut down and methodical troubleshooting activities. Although the plant was designed to operate with more than one waterbox out of service, the licensee conservatively maintained the plant shut down until the leaking condenser was identified, based on chemistry results. The specific, leaking "C" condenser tube was identified and plugged shetly after restart.
O1.2 Manual Reactor Trio Due to Storm-related. Imminent Loss of Condenser Vacuum a.
Insoection Scone (71707)
Operators manually tripped the reactor from 90 percent power on November 11,1998, due to an anticipated turbine trip / reactor trip due to the loss of condenser vacuum. The inspector was notified and briefed on the event that day. In the days following the event, the inspector observed licensee evaluation of and corrective actions for the trip.
b.
Observations and Findinas In response to a storm in the area, operators reduced power from 100 percent to 90 percent j
and were attempting to backwash the condenser to prevent seaweed fouling of the condenser heat exchangers. During this evolution, which requires one of two condenser circulating pumps (6 total) per condenser (3 total) to be turned off, the second pump tripped on high differential pressure. Since the attea pts to backwash were not effective and operators knew that loss of two of the pumps would threaten condenser vacuum, operators manually tripped the plant. The inspector discussed this action with operations personnel and confirmed it was in accordance with OP 3215, Respor' / to intake Structure Degraded Conditions. All systems operated as expected.
The licensee immediately assembled an event review team (ERT) to investigate the cause of the event and to recommend actions to be completed before the unit was restarted. The inspector attended the ERT briefing to plant management and PORC and reviewed the final ERT report. The licensee determined that inadequate planning for the storm condition contributed to the event. Before restart, the inspector verified that relevant procedures were revised to ensure that key members of the organization are aware of weather conditions earlier, to effect more timely response and preparation for storms.
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The safety significance of this trip was low, due to the f act that the reactor was tripped, as I
required, and the water levelin the bays did not go below a level which would have
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threatened the operability of the safety-related service water pumps. No radiological releases resulted from this event.
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Conclusions Unit 3 operators manually tripped the plant during a rain storm in accordance with procedures when imminent loss of condenser vacuum was anticipated. The licensee
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promptly convened an event review team and implemented appropriate corrective actions prior to restarting the reactor.
U3 07 Quality Assurance in Operations 07.1 Review of Oversicht Assessments. Soecial Reoorts. Reaulatorv Comoliance Positions. and Third Partv Reviews a.
insoection Scoce (71707. 90712. 92901)
The inspector reviewed the Nuclear Oversight monthly report, several surveillance reports, and the weekly 50.54(f) recovery oversight status reports, as well as a listing of the status of Nuclear Safety Assessment Board (NSAB) open action items. The inspector also reviewed a special report, submitted pursuant to the Unit 3 technical specifications (TS) on the " Loose Part Detection System" and conducted further inspection of an inspector followup item regarding the licensee's interpretation of TS requirements and limiting conditions for operation (LCO). Finally, the inspector conducted a review of a recent third party evaluation report of Unit 3 programs and performance, b.
Observations and Findinas The inspector's review of the Nuclear Oversight (NOS) Monthly Report, dated November 23, 1998, noted consistency with separate surveillances on the corrective action program, the self-assessment program, and the conduct of engineering - all completed by NOS personnel in the October / November 1998 time frame. In accordance with the Nuclear Oversight Verification Plan (NOVP) procedure, NOQP 1.08, defining the performance standards, the different areas assessed by NOS appeared to be appropriately categorized. The inspector noted NOS recognition of an " operational focus" at Unit 3, documenting the need for licensee management attention to attain a proper balance between backlog reduction and other site priorities Likewise, the review of both the NSAB open action items and Recovery Oversight assessment activities indicated consistency with several performance issues (e.g.,
backlog processing, corrective actions for the Joint Utility Management Audit) being tracked by NOS.
The inspector also reviewed a "Special Report - Loose Part Detection System", submitted to l
the NRC on September 9,1998, pursuant to TS 3.3.3.8 because thirty days had passed
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since the loose parts monitoring (LPM) system was declared inoperable. While the LPM power supply units had been replaced, the impact of input signal " noise" on the exact
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sensitivity and calibration characteristics of the system appears to remain in question. On l
November 19,1998, the !icensee updated the LPM system status with a licensee event report, LER 98-042-00, documenting as a historical condition some deficiencies with the surveillance procedure and calibration requirement for the LPM system. Licensee investigation has determined that the LPM system will not be able to be restored to an operable status until the completion of system testing following the next refueling outage i
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MFO6), scheduled in mid-1999. The inspector noted that the LPM system, while inoperable, is still considered available by the licensee for the identification of loose parts in l
monitored reactor system components. The inspector confirmed appropriate licensee i
response to and evaluation of LPM alarm conditions, and determined that the licensee's submission of LER 98-042-00 adequately supplements the LPM Special Report, with corrective measures being planned to restore the full system capability after restart from RFO6.
l During the conduct of previous NRC inspection activities in 1997, the inspector documented
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an inspector followup item, IFl 50-423/97-01-06, to evaluate the Unit 3 policy for
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interpreting TS language and LCO actions. Subsequently, as documented in inspection report (IR) 50-423/98-206, a NRC inspector reviewed the licensee's Technical Requirements
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Manual (TRM), for use as a supplement and clarifying document to the unit operating license TS requirements. As a result of that inspection, no conflicts or regulatory problems between the TS provisions and TRM guidance were identified. As documented in the last NRC inspection report for Unit 3, IR 50-423/98-216, a Regulatory Compliance Position on l
Cascading TS was issued as a Regulatory Affairs and Compliance (RAC-98-279) guidance l
document on September 18,1998. At that time, the licensee appropriately used the
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published TS guidance to evaluate an im erter failure and other plant conditions for proper LCO entry. Based upon successfulimplementation of such guidance, along with evidence of continued acceptable TRM usage, the inspector has no additional followup questions on the control of TS and LCO interpretations; and therefore considers IFl 50-423/97-01-06 to
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be closed.
In accordance with the guidance delineated in NRC inspection procedure (IP) 71707, the inspector conducted a review of the third party evaluation (INPO) report of Unit 3 performance and activities, performed in August 1998. The inspector assessed the
documented findings and strengths in all evaluation areas, in the context of NRC perceptions of licensee performance in these areas (e.g., operations, maintenance, engineering). Overall, the results of this third party review were generally consistent with both the current NRC inspection results and the recent NRC assessments of licensee and Unit 3 performance documented in NRC staff position papers submitted to the Commission j
for review and attention, i
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Conclusions l
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Review of NOS, NSAB, and Third Party evaluation documents all provided findings,
conclusions, and recommendations consistent the NRC view of Unit 3 performance and the
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need for strong " operational focus" for continued improvement. Both the TRM and RAC
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guidance on TS and LCO action interpretations continue to be appropriately used to ensure
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compliance with regulatory requirements. The inoperability, but availability, of the LPM i
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l system has been properly reported to the NRC, and will continue to be tracked as followup to LER 98-042-00.
a U3 08 Miscellaneous Operations issues (92700)
08.1 (Closed) Violation 50-423/97-83-01: failure to correctly implement procedure changes in accordance with TS 6.8.3. Operators routinely deviated from procedures by using inappropriate administrative processes. The licensee performed a 100% review of J
the 3300 series system lineup procedures. Deficiencies that were identified were promptly corrected. Additionally, a sample of 33 system lineup procedure revisions were reviewed with the procedure writers group to assure they were appropriately incorporated. The station administrative procedures were revised to include a " Temporary Change" process.
Unit 3 shift managers attended training presentations on "The use of N/A to indicate non-performance of procedural steps," and " Determining if a modification alters the original intent." The inspector reviewed the results of the licensee's reviews and procedure changes, and concluded that the corrective actions were appropriate. This violation is closed.
08.2 (Closed) Violation 50-423/97-83-02: f ailure to have two operable reactor coolant system loops in Mode 4, as required by TS 3.4.1.3. The licensee provided training and briefings to the operations crews regarding this event, emphasizing the importance of verifying information, proper use and satisfaction of acceptance criteria, and surveillance validation. The inspector reviewed the training material and verified operator attendance.
The surveillance procedure SP 3601D.1, " Reactor Coolant Pump Operability," Revision 4, was revised to clarify the TS acceptance criteria for Mode 4 with the reactor trip breakers open. The licensee's corrective actions for this event were appropriate. This violation is closed.
08.3 (Closed) Violation 50-423/97-83-03: failure to implement procedure requirements on three occasion. Operators did not follow OP 3301G, " Pressurizer Pressure Control," step 4.1.6, when placing the pressurizer pressure master controller in automatic. Operators did not maintain the "C" SG generator level between 45% and 55% as required by OP 3201, Plant Heatup. The licensee failed to perform a preventive maintenance task on the turbine driven auxiliary feedwater pump within its grace period in accordance with U3 CBM 105,
"PM Program Changes and Deferrals for Unit 3." The licensee performed extensive root cause investigations for the operational events, which resulted in comprehensive corrective actions that were completed prior to the Unit 3 startup in July 1998. The inspectors reviewed the corrective actions, concluded that they appropriately addressed the deficiencies identified in the root cause evaluations, as well as the operator performance issues, and documented the results in NRC Inspection Report 50-423/98-208, dated August 12,1998, Section U3.01.2. This violation is closed.
08.4 (Closed) Violation 50-423/97-83-04: f ailure to determine if the pressurizer temperature was within limits every 30 minutes in accordance with TS 3.4.9.2. The individual responsible for the missed reading was counseled regarding this event. The Operations Department conducted training sessions regarding the event, as well as initiating an operations briefing sheet detailing the importance of pre-job briefs, and roles and
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responsibilities required when performing tasks. These corrective actions were adequate and this violation is closed.
08.5 (Closed) Violation 50-423/97-83-06: f ailure to establish measures to assure that conditions adverse to quality, such as deficiencies, were promptly identified and corrected.
System alignment deficiencies were not promptly identified and corrected including, valves not aligned in accordance with the alignment sheets, independent verifications not performed, and system alignment procedures not completed. The licensee performed root cause investigations for the valve and system alignment deficiencies, which resulted in comprehensive corrective actions that were completed prior to the Unit 3 startup in July 1998. The inspectors reviewed the corrective actions, concluded that the licensee took extensive actions to correct identified equipment alignment weaknesses, and documented the results in NRC Inspection Report 50-423/98-208, dated August 12,1998, Section U3.01.3. This violation is closed.
08.6 (Closed) Violation 50-423/97-83-OL failure to verify potential dilution path valve position with a shutdown margin monitoring channelinoperable, as required by TS Table 3.3-1, Functional Unit 21, Action 5(a). The licensee performed a root cause investigation concerning this event and determined that the cause of the condition was attributed to human error in that the shift manager failed to recognize the need to complete the required surveillance in the allowed time. Immediate corrective actions were taken to verify that the boron dilution pathways were secured. Operations personnel attended a training session with unit management, which emphasized heightened operator awareness and efficient time management associated with TS limited conditions of operations (LCO) action statement requirements. The inspector reviewed the attendance records to verified appropriate operator participation. The licensee also revised the Shift Daily Status Report to include additional detail in order to assure that TS LCO action requirements were given the proper focus. LCO action statements " coming due" and "in effect" are individually listed at the beginning of the report. The inspectors concluded that the corrective actions were appropriate.
08.7 (Closed) LER 50-423/98-24: " Failure to Complete the Action Statement Associated with Technical Specification 4/3.3.1 Within the Required Time Period." The inspector review a closure package for this LER, which documented the condition discussed in violation 97-083-07, and included the corrective actions stated above. This violation, as well as the associated LER are closed.
U3.ll Maintenance U3 M1 Conduct of Maintenance M 1.1 Surveillance Observations a.
insoection Scoce (61726)
Using inspection procedure 61726, the inspector observed portions of selected surveillance activities to verify proper calibration of test instrumentation, use of approved procedures,
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conformance to TS limiting conditions for operation, and correct system restoration following testing. The following activities were observed:
e SP 3606.1 Containment Recirculation Pump 3RSS*P1 A Operational Readiness Test e SP 3622.3 Auxiliary Feedwater Pump 3FWA*P2 Operational Readiness Test e SP 3606.8-1 RSS Valve Stroke Time Test - Train A b.
Observations and Findinas Activities were performed by knowledgeable operators, condition based maintenance, and instrumentation and controls (l&C) technicians in accordance with approved procedures.
Observed pre-job briefings were thorough in that they addressed the scope of work to be performed, outlined expected effects on control room indications, and stressed no time pressure, procedural adherence and effective communication between the control room and in-plant workers.
The inspector independently verified selected prerequisites were complete prior to performance of the procedures and confirmed that no termination criteria were reached during the tests. A review of operator logs confirmed operators logged into and out of the appropriate TS LCOs for testing and any associated maintenance activities.
Plant personnelidentified a !ow level in the steam driven auxiliary feed pump turbine governor during the pump run and appropriately requested maintenance assistance to restore level. Although this evolution took approximately two hours, and extended the time in the TS LCO, the inspector determined that it was an appropriate response by operators and the extra run time had no adverse effect on the turbine. The inspector noted that a CR was written to document the low oillevel and surveillance documentation accurately reflected the as-found and as-left conditions. The system engineer observed turbine operation during the test to identify potential problems and was aware of the low oil level.
The inspector verified systems were returned to their normal configurations after testing. In addition, completed surveillance forms were reviewed and no as-left acceptance criteria were exceeded.
c.
Conclusions Knowledgeable operators and maintenance and instrumentation and control technicians performed observed Unit 3 surveillance activities in a controlled and professional manner, utilizing approved procedures. Appropriate pre-evolutionary briefs were performed before each activity and adequate communication was maintained. Problems identified during testing were effectively corrected. Equipment was satisfactorily returned to normal configuration following testing activities.
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U3 M2 Maintenance and Material Condition of Facilities and Equipment M 2.1 Comoonent Maintenance and Troubleshootina a.
Insoection Scone (62707)
The inspector conducted reviews of the weekly and daily work plans to evaluate control of the equipment removed from service for preventive maintenance or troubleshooting activities. Coordination of such work with operational cognizance of technical specification impact and risk perspectives was generally confirmed. The inspector witnessed on-shift operator conduct related to various maintenance activities (e.g., slave relay testing) and performed inspection tours of several areas in the plant where component maintenance was in progress.
b.
Obgrvations and Findinas As documented in the last resident inspection report, 50-423/98-216, the troubleshooting plan and maintenance work in response to the loss of the inverter no.1 (3VBA*lNV1)
supplying a 120Vac vital bus had been reviewed to assess the licensee's causal determination and corrective actions. The inverter vendor (Elgar) performed shop j
testing / failure analyses on the as-found condition of the firing cards that could be related to
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the observed fuse f ailure.
During this inspection period, the inspector reviewed the Elgar report documenting the results of these testing activities. While the test results found no defects or conditions outside specification requirements for the instrument cards and logic assemblies, the Elgar inspection noted that a driver logic board represented an earlier vintage of the assembly that had since been updated by later revisions to prevent fuse-clearing problems, The licensee replaced the subject logic board with one manufactured to a later revision. Inverter no.1 was returned to service with the blown fuse replaced and with new cards and assemblies installed. As of the conclusion of this inspection period, no additional problems with performance of inverter no.1 were observed.
Upon the return of Unit 3 to power operations, subsequent to the manual reactor trip documented in section 01.1 of this inspection report, the licensee noted a small body-to-bonnet leak on the "B" main steam line feedwater isolation valve,3FWS*CTV41B. New studs with special encapsulation nuts were installed in all twenty flange joint positions; new and higher torque criteria were evaluated and approved; and provisions for leak sealant injection of the body-to-bonnet interface were made ready, if necessary to stop the leak.
The inspector conducted an inspection of the subject valve, noting that after the higher torque application to the stud nuts, the leaks were only visible by means of indirect view, e.g. a mirror or f ace shield to confirm fogging. The inspector confirmed proper tag-out
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controls and verified that plant equipment operators were checking leak conditions on routine rounds.
The inspector assessed the controls of this maintenance activity, implemented as a temporary modification (TM 3-98-068). The safety evaluation screen form, the technical
evaluation (M3-EV-98-0170), and the design evaluation were reviewed, to include verification of seismic design considerations, appropriate material specifications and independent calculations for sealant injection. Subsequently, the licensee decided to postpone any leak seat injection into the valve body-to-body joint, based upon the minor leakage in evidence. The inspector evaluated this decision, confirming the existing minor leakage conditions. the inspector concluded that valve operability was not impacted and that the continued implementation of TM 3-98-068 was acceptable, with future leak injection available as a contingency option.
c.
Conclusions Review of inspected troubleshooting, failure analysis, and maintenance repair activities revealed the implementation of adequate controls by the licensee. The proper use of a temporary modification, including a safety evaluation, was verified. The inspector determined that based upon the observed component conditions for both inverter no.1 and 3FWS*CTV41B, as well the continued monitoring of equipment status by the licensee, the scope of licensee maintenance / repairs for these components, at this particular time, was deemed appropriate.
U3 M8 Miscellaneous Maintenance issues M 8.1 Review of Licensee Event Reoorts a.
Insoection Scooe (92700)
The inspector reviewed the following Licensee Event Reports (LERs), assessing the adequacy of the identification, reporting, evaluation, supplementation, and resolution of each individual issue. The review was conducted onsite and included examination of associated licensee documentation to include condition reports, root cause analyses, action requests (A/R) assignments, as applicable, as well as field inspections and verification of a selected sample of corrective actions.
b.
Observations and Findinas Update to Corrective Actions of LER 50-423/97-017-02," Inadequate Testing of Logic Circuits" (reference: Northeast Nuclear Energy letter, B17386, dated November 12,1998)
(Closed) LER 50-423/97-050-00, "Non-Environmentally Qualified Parts Installed in Safety Related Components" (Closed) LER 50-423/97-S001-00, " Vital Area Barrier Gratings in Main Steam Valve Building Floor Not Secured" An inspection of the corrective actions related to LER 97-017, including supplements 1 & 2, was conducted and documented in inspection report 50-243/97-208, at which time this LER was closed. During this current inspection period, the licensee submitted an updated
compilation of the regulatory commitments that have been completed relative to this LER, along with a status of the corrective actions taken to address the issues identified in an associated Generic Letter (GL 96-01), " Testing of Safety Related Logic Circuits". The inspector reviewed the listed commitments, the actions taken by the licensee to comply, and the various dates associated with the completed corrective actions. As previously documented by the licensee, all the corrective measures had been completed prior to heating the unit to Mode 4 (hot shutdown) conditions. The inspector identified no discrepancies between the licensee's update letter and the documented, completed activities.
The inspector reviewed all four corrective action commitments documented in LER 97-S001-00. A record of the training of maintenance personnel, relative to expectations for reinstalling fasteners on gratings that constitute vital area barriers, was examined. The inspector verified the revision to both security instructions and the Production Maintenance Management System (PMMS) data base to reflect security guard posting when the vital barrier grating latches are removed and evidence of the bolt replacement prior to returning the affected area to normal operation. The inspector also conducted a field inspection of the subject building, both from inside and outside the vital areas, and confirmed secure zones and the existence of numerous signs indicating the need to contact Security prior to breaching the grating boundaries.
With regard to LER 97-050-00, this issue was previously inspected as documented in inspection report 50-423/98-207, with the determination that appropriate corrective actions had been implemented by the licensee; noting however that the completion of programmatic environmental qualification (EQ) rneasures were needed for closure of this item. During this current inspection, the inspector reviewed licensee documentation providing evidence of the EQ training of personnel; the development of the required EQ procedures and guidance in the form of a revision to affected EQ Program Manual, as supplemented by Nuclear Safety Engineering memoranda; and the input of EQ program indicators into the PMMS database.
These corrective measures, along with the establishment of an EQ Program Coordinator to provide technical support and direction to personnel involved in EQ component activities in Unit 3, provide the necessary evidence of a management level of support to permit closure
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of this item. The inspector noted that a root cause analysis had been conducted by the licensee to address the condition reports related to this LER.
c.
Conclusions Licensee corrective actions for all three LERs, including the update of revised and completed regulatory commitments, were determined to be acceptable. The corrective measures were commensurate with the safety significance of the self-identified problems and included consideration of long term programmatic initiatives to preclude problem recurrence.
j Reportability, timeliness, event analysis requirements have been met. These non-repetitive, l
licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Policv. LERs 97-017-02,97-050-00, and 97-S001-00 are hereby closed as non-cited violations, NCVs 50-423/98-05-05,06,
& 07, respectively.
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U3.Ill Enaineering U3 E7 Quality Assurance in Engineering Activities E7.1 Review of Unresolved item Status
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a.
Insoection Scoce (92903)
The inspector reviewed the status of two existing unresolved items with impact on specific l
engineering problem areas. Previous NRC inspections reviewed the engineering programs that represented the topical subject of these open items. During this inspection, the inspector evaluated whether completed or ongoing licensee corrective actions were sufficient to adequately address the remaining unresolved issues associated with these items, b.
Observations and Findinas (Closed) Unresolved item, URI 50-423/96-09-11, ARCOR Epoxy Lining Failures.
(Closed) Unresolved Item, URI 50-423/97-203-11, Appendix R Equipment Testing.
As documented in NRC inspection report (IR) 50-423/96-09, pieces of ARCOR epoxy fining internal to the service water (SWP) piping were found by the licensee on the inlet side of l
some heat exchangers cooled by the SWP system. An unresolved item was opened to track the effects of this ARCOR delamination on safety-related equipment and further assess the
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I licensee's safety evaluation review and root cause investigation. Subsequently, the NRC elevated this issue to significant items list (SIL) status, requiring the acceptable disposition of corrective actions prior to Unit 3 restart. The licensee's conduct of special testing of existing and newly applied ARCOR coatings was inspected, as documented in IR 50-423/97-202, at which time a procedural violation was identified and issued to the licensee by the NRC.
During the conduct of the follow-up inspection (IR 50-423/98-206) of the licensee corrective measures to address the procedural violation, a NRC inspector concluded that corrective actions were adequate, including 100% piping visualinspection and necessary coating repairs and that the licensee's root cause analysis had been thorough. As a result of this review, both the existing ARCOR violation and the respective SIL ltem were closed.
During this current inspection period, the inspector conducted a re-review of the corrective actions implemented to preclude any future adverse safety impact, based upon the known ARCOR delamination problems. Given that ARCOR lining debris is occasionally found at the inlet to heat exchangers, as documented in condition reports, the inspector assessed these conditions, determining that random coating degradation resulting in small material particles l
in the flow stream did not represent a significant safety concern. The licensee corrective l
measures taken to address the more significant ARCOR delamination appeared to be
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effective and will continue to be monitored during future heat exchanger and SWP piping inspections.
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With respect to the Appendix R equipment testing questions raised and documented as an unresolved item in IR 50-423/97-203, the inspector noted that a related unresolved item had been identified with regard to the adequacy of surveillance testing of safe shutdown
equipment during a team inspection (lR 50-423/97-84) of the post-fire safe shutdown program at Unit 3. A subsequent team inspection (IR 50-423/98-81) of the Unit 3 Fire Protection Program assessed licensee efforts to reconstruct historical construction testing records and to perform additional surveillance tests to ensure all post-fire safe shutdown equipment was operable. The inspectors, at that time, determined the licensee corrective action to be appropriate and dispositioned the identified concerns as a non-cited violation.
During this current inspection, the inspector reviewed the specific Appendix R issues related to URI 97-203-11 and determined that they had been adequately addressed by the NRC fire protection team inspections, noted above. The adequacy of component testing and the impact upon equipment operability, relative to Appendix R safe shutdown requirements, had been reviewed by NRC inspectors in their assessment of licensee corrective measures and the determination that the subject equipment was operable.
c.
Conclusions The inspector noted that licensee corrective actions to resolve separately documented NRC open issues on ARCOR lining degradation and Appendix R testing discrepancies, also addressed the remainino NRC questions on the two subject unresolved items. The inspector verified that prior NRC inspections had reviewed and appropriately dispositioned the specific and programmatic concerns. Therefore, URis 423/96-09-11 & 97-203-11 are both hereby considered to be closed.
U3 E8 Miscellaneous Engineering issues E8.1 (Closed) IFl 50-423/95-01-01 Item 2: Comolete load sensitive behavior and stem friction coefficient analvses (92903)
in its motor-operated valve (MOV) design calculations, NNECo based its assumptions concerning load sensitive behavior and stem friction coefficient on data from the Electric Power Research Institute's (EPRI) performance prediction program and a limited amount of in-plant dynamic testing, in a letter to the NRC, dated April 25,1998, NNECo committed to document in an engineering calculation its analysis of in-plant test results against the assumptions based on the EPRI test program. Followup items 50-423/98-82-04 and 50-423/98-82-05 were opened to track NNECo's disposition of these matters. Both followup items were closed in Millstone 3 Inspection Report 50-245, 336, & 423/98-208, based on the inspector's review of calculation 89-094-01513, " Dynamic Test Results," the Millstone
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3 MOV alternate test plan, and relevant dynamic test evaluation forms. During this inspection period, the inspector conducted an in-office review of the issues involved with this IFl and determined that this redundant item is also close E8.2 (Closed) LER 50-423/97-021-00: Defective Desian of Recirculation Sorav Svstem (RSS) Exoansion Joint Tie Rod Assembiv a.
Insoection Scope (92903)
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The licensee identified that defects existed in the original design of tie rod assemblies in eight RSS expansion joints (3RSS*EJ1 A through D, and 3RSS*EJ2A through D). The specific design deficiency is a failure to provide adequate clearance for intermediate tie rod
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nuts. As a result of this defect, if the joints were subjected to their design basis loads, the stress levels in the joint tie rod assembly could have exceeded its analyzed operating limits and the joint could have deformed. The inspector performed an in-office review of the adverse condition report (ACR) M3-97-0407, which documented and evaluated the event;
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action request (AR) 97003749, which assigned corrective actions; licensee event report (LER) 50-423/97-021-00, which reported the event in accordance with 10 CFR 50.73(a)(2)(ii); the root cause investigation associated with the issue; and the associated design control changes and documents.
b.
Observations and Findinos The licensee's root cause investigation determined that (1) the defective design was issued by the vendor as a result of a breakdown in the vendor's internal design review process, and (2) the defect was not discovered by subsequent reviews due to a lack of specific expertise in the design of expansion joints. The licensee's corrective actions included performing physical modifications to the eight RSS expansion joints, reviewing the design requirements for the other expansion joints designed by the vendor, and reviewing the design requirements for expansion joints designed by other expansion joint vendors.
The inspector reviewed the design control records (DCRs) associated with the rework of the eight expansion joints (DCRs M3-96054 and M3-97063) and verified that the work was completed. The inspector noted that, due to unrelated problems in the system, the licensee replaced RSS expansion joints 3RSS*EJ1 A through D with a solid pipe spool piece prior to the June 1998 restart. This modification was reviewed in Inspection Report 50-423/98-207, dated June 19,1998. The inspector did not have any comments on the physical work associated with the eight expansion joints.
The inspector reviewed the results of the plant-wide review of ASME Ill expansion joints.
The licensee's review identified several instances where the drawings of record indicated that non-QA materials were used, which does not meet ASME requirements. This material was replaced with the appropriate ASME material where required. No other discrepancies were noted. The inspector determined that the licensee's corrective actions were appropriate. This licensee-identified and corrected violation is being treated as a non-cited violation, in accordance with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 423/98-05-08)
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Conclusions The licensee's corrective actions in response to a design deficiency in the tie rod assemblies for eight Unit 3 RSS expansion joints are acceptable. This licensee-identified and corrected violation is being treated as a non-cited violation. LER 97-021-00 is considered closed.
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IV Plant Suooort F2 Status of Fire Protection Facilities and Equipment F2.1 Fire Penetration Seal Installation and Reoair (Unit 21 a.
Insoection Scone (64704)
The inspector reviewed approximately 50 fire penetration sealinstallation and repair work orders, performed between 1984 and 1991, to determine if the seals were worked and inspected in accordance with MP 2721N, " Sealing and Seal Repair of Electrical Cable and Piping Penetrations." Also, the NRC inspector walked-down and visually inspected a sample of the fire seals in the cable spreading room, control room, and the A and B battery rooms for physical damage, color, cell structure, shrinkage, presence of required permanent damming material, and seal separation.
b.
Observations and Findinas The inspector found that the work orders were generally completed in accordance with MP 2721N. The inspector found that the quality and consistency of the work orders improved with the implementation of subsequent revisions to MP 2721N, " Sealing and Seal Repair of Electrical Cable and Piping Penetrations." The inspector identified several work order discrepancies associated with work conducted in 1984, as part of M2-84-06200. This work order had approximately 80 repairs in which the seal fill depths were indeterminate.
Procedure MP 2721N, " Sealing and Seal Repair of Electrical Cable and Piping Penetrations,"
Rev. 3, section 5.1, allowed the depth of the seals to be extended to 12 inches in lieu of the installation of 1 inch of damming board. Quality Control (QC) did not verify that these penetration repairs achieved the required fill depth nor, did the licensee have available evidence to show that the condition was evaluated and met the required fire rating.
Pending NRC review, this issue remains unresolved. (URI 50-336/98-05-09)
The licensee, as part of the ongoing recovery activities of Millstone Unit 2, initiated an inspection of fire barrier penetration seals to meet Technical Requirement Manual (TRM)
surveillance requirements. The licensee completed a 100% sealinspection under " Fire Penetration Seal Inspection" SFP-17 on September 30,1998. The procedure requires, in part, a visualinspection of each seal to ensure the following:
a.
Seal is in place c.
Seal has not been damaged or altered.
d.
Seal deterioration does not exceed the inspection requirements listed in Attachment 3. This attachment required, for silicone foam, no cracks or gaps in the seal surface greater than 0.25 inches wide by 1.75 inches deep (length does not matter) or greater than 1 square inch by 0.5 inch dee __
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According to the licensee, the inspection is intended to only identify degradation in the seals. Verification of the seal configuration is not in the scope of the inspection. The inspection revealed sixty eight defective seals.
Based on the programmatic deficiencies that were identified during the 1998 SFP-17 inspection, the licensee issued Condition Report M2-98-2317 to establish an Executive Sponsor and Issue Marager to continued to review the adequacy of the site Fire Protection Program. Additionally, CR M2-98-2317 initiated corrective actions to address the identified programmatic deficiencies. These corrective actions include the forensic inspection of seal during replacement and repair for voids (no assigned due date) and the verification of the installed seal configurations (assigned due date 9/12/99). The specifics of these corrective actions were under development and not implemented or available for review during the course of the inspection.
Two barriers, in which required damming material was not installed, were identified in October 1998, during an engineering configuration walk down initiated in response to NRC questions. The seal design for the cable tray 8-33A penetration identified the requirement for fire board damming and none was visible. The licensee determined that the current configuration met the required fire rating and initiated CR-M2-983037 to address the configuration documentation deficiency. Additionally, the seal design for conduit 9-15 penetration required fire board and none was visible. The conduit was found to be sealed internally with a very hard, dried "Duxseal@"like material. The licensee determined that this was not an approved fire tested penetration seal material. The licensee established compensatory actions for the deficient seal and initiated CR-M2-98-3123 to address this issue. The failure to use approved materialin a fire penetration sealis the first example of a violation of the Millstone 2 fire protection requirement. (VIO 50-336/98-05-010)
The inspector identified several work orders in which repairs were made to Dow Corning 3-6548 silicone foam seals with Dow Corning 96-081 adhesive / sealant that had conflicts in documentation and appeared to not meet the repair criteria established in MP 2721N,
" Sealing and Seal Repair of Electrical Cable and Piping Penetrations," fire barrier qualification tests, or NUREG-1552, section 5.7. Specifically, MP 2721N, " Sealing and Seal Repair of Electrical Cable and Piping Penetrations," Revisions 2 and 3, step 5.10.5, states that repairs to foam seals using Dow Corning 96-081 adhesive / sealant are limited to one half (%) inch or less in width. Step 5.11.1 requires repairs to adhesive / sealant to use one inch of damming and at least two inches of adhesive / sealant.
Based on the inspector's concerns with the seal repair configurations, the licensee conducted a review of the fire penetration seals, installed between 1984 and 1991, and determined based, on a review of the repair work orders, that six work orders (M2-84-06200, M2-85-04961, M2-85-09501, M2-87-0165, M2-87-01807, and M2-88-10956)
could be outside of the tested design configuration. Specifically, the licensee could not demonstrate that the configurations were tested in accordance with the ASTM E-119 Fire Endurance Test and had a three hour fire rating. The six identified work orders repaired 18 of the plants approximate 4000 seals. The licensee initiated CR M2-98-3580 to address these discrepancies. The failure to restore deficient seals to a configurations that has been tested in accordance with the ASTM E-119 Fire Endurance Test and evaluated to have a
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As described in memo PES-98-388, " Quality of 1998 Fire Penetration Seal inspection (SFP-17)," the licensee has identified a total of 23 unsatisfactory penetration seals subsequent to the 1998 SFP-17 completion. This matter will be further reviewed as part of the NRC review of the Significant items List (SIL) prior to the restart of Unit 2.
c.
Conclusion The inspector concluded that the seals that were sampled were satisf actory with regards to physical damage, presence of required permanent damming material, shrinkage and separation. The quality and consistency of the work orders improved with the implementation of subsequent revisions to MP 2721N. The issues involving indeterminate seal fill depths remains unresolved (URI 50-336/98-05-09). Additionally, the inspector identified a violation in which several penetration seals were not install or repaired to a tested configuration in accordance with the Millstone 2 fire protection requirement.
F3 Fire Protection Procedures and Documentation F3.1 Fire Penetration Seal Audit (Unit 2)
a.
insoection Scone (647041 The licensee conducted a work order review of penetration seals, installed between 1984 and 1991, to determine if expired materials were used during the seal installations and repairs. To independently verify the licensee's results, the inspector reviewed approximately 50 of the fire penetration seal work orders, licensee self audit results, and interviewed the Unit 2 fire protection engineer and engineering assurance senior engineer.
b.
Observations and Findinas The inspector found that the licensee conducted comprehensive review of fire penetration seals, installed between 1984 and 1991 by retrieving and comparing the material batch / lot numbers, along with their corresponding material expiration dates from the certificate of conformance (C/C) and the certificate of analysis (C/A), to the installation dates and final inspection dates. The licensee determined that the shelf life expired on Dow Corning 96-081 adhesive / sealant that was installed in approximately 40 fire penetration seals and the shelf life expired on Dow Corning 3-6548 silicone foam that was installed in 2 penetrations.
Additionally, the shelf life was indeterminate for Dow Corning 96-081 adhesive / sealant used in 7 work orders and Dow Corning 3-6548 silicone foam used in 2 work orders.
However, the Dow Corning 3-6548 silicone foam that had exceeded its shelf life was used within the manufacturer's warranty date. The majority of expired Dow Corning 96-081 adhesive / sealant was used for seal repairs and exceeded the shelf life by a maximum of seven months. Through consultation with the vendor and a survey of the expired material
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usage, the licensee determined that there were no operability issues with the identified seals. The licensee initiated CR M2-98-3069 to address the use of expired material.
Technical Specification (TS) 6.8.1.f requires that written procedures be established, implemented, and maintained covering Fire Protection Program implementation. TS 6.8.1.i applies to the installation of Firestops and Seals procedure. The f ailure to use materials
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within the shelf life, in accordance with MP 2721N, " Sealing and Seal Repair of Electrical Cable and Piping Penetrations," was a violation of TS 6.8.1.f. This f ailure constitutes a minor violation and is not subject to forrd enforcement actions.
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c.
Conclusion
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The inspector concluded that the licensee conducted a comprehensive self audit. The use j
of expired seal materials, which resulted from tha failure to follow fire barrier seals installation procedures, constitute a minor violation.
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L Manaaement Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at separate meetings at the conclusion of their inspection activities. The licensee acknowledged the findings presented.
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INSPECTION PROCEDURES USED IP 42001 Emergency Op6 rating Procedures IP 61726 Surveillance Observations i
IP 62707 Maintenarice Observation IP 64/04 Fire Protection Program IP 71001
. Licensed Operator Requalification Program Evaluation IP 71707 Plant Operations IP 90712 Inoffice Review of Written Reports of Nonroutine Events i
IP 92700 Onsite follow-up of Written reports of Nonroutine Events at Power Reactor Facilities IP 92901 Followup - Plant Operations
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IP 92902 Follow-up Maintenance IP 92903 Follow-up Engineering i
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ITEMS OPENED, CLOSED, AND DISCUSSED items Ooened TYPE ITEM NUMBER DESCRIPTION SECTION NCV 336/98-05-01 HDFA AND HANDLING TOOL WEIGHT U2.08.1 EXCEEDS TS LIMIT NCV 336/98-05-02 INSERVICE TESTING INSTRUMENT U2.E8.4 CAllBRATION REQUIREMENTS NOT SATISFIED NCV 336/98-05-03 EXCEEDED LICENSED PvWER LEVEL U2.E8.6 IFl 336/98-05-04 VERIFY CALCS FOR BLOWDOWN FLOW U2.E8.6 EFFECTS ON PRl/SEC LEAKAGE NCV 423/98-05-BASED ON LERS 97-017-02, 97-050-00 U3.M8.1 l
05/06/07 AND 97-S001-00, RESPECTIVELY NCV 423/98-05-08 TIE ROD ASSEMBLY AND RSS U3.E8.2 EXPANSION JOINTS URI 336/98-05-09 ADEQUACY OF PENETRATION SEAL F2 l
REPAIRS VIO 336/98-05-10 FAILURE TO SATISFY PENETRATION F2 l
SEAL TESTING AND CONFIGURATION l
REQUIREMENTS l
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Items Closed LER 336/97-010-00 SECTION U2.08.1 NCV 336/98-05-01 SECTION U2.08.1 URI 336/97-203-04 SECTION U2.08.2 LER 336/96-039-00 SECTION U2.M8.1 LER 336/96-040-00 SECTION U2.M8.2 LERs 336/97-03-00&O1 SECTION U2.M8.3 eel 336/96-04-10 SECTION U2.E8.1 URI 336/96-04-11 SECTION U2.E8.1 URI 336/96-201-38 SECTION U2.E8.2
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LER 336/97-005 00 SECTION U2.E8.4 i
NCV 336/98-05-03 SECTION U2.E8.4-LERs 336/97-033-00&O1 SECTION U2 E8.5 IFl 423/97-01-06 SECTION U3.07.1 VIO 423/97-83-01 SECTION U3.08.1 VIO 423/97-83-02 SECTION U3.08.2
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VIO 423/97-83-03 SECTION U3.08.3 i
VIO 423/97-83-04 SECTION U3.08.4 VIO 423/97-83-06 SECTION U3.08.5 VIO 423/97-83-07 SECTION U3.08.6 LER 423/98-024-00 SECTION U3.08.7 NCVs 423/98-05-04/05/06 SECTION U3.M8.1 LER 423/97-017 02 SECTION U3.M8.1 i
LER 423/97-050-07 SECTION U3.M8.1 LER 423/97-S001-00 SECTION U3.M8.1 URI 423/96-09-11 SECTION U3.E7.1 URI 423/97-203-11 SECTION U3.E7.1
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NCV 423/98-05-07 SECTION U3 E8.2 l
Items Undated eel 336/97-02-12 SECTION U2.M8.1/M8.2/M8.3 Eels 336/96-201-42&43 SECTION U2.E.. - -. ~.. - - -. -... _ - -. -
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LIST OF ACRONYMS USED ACR(s)
adverse condition report (s)
AOP(s) -
abnormal operating procedure (s)
ATI automatic test inserter AWO(s)
automated work order (s)
C/A Certificate of Analysis C/C Certificate of Conformance CFR Code of Federal Regulations DCR
' design control record i
eel (s)
escalated enforcement item (s)
EOP(s)
emergency operation procedure (s)
EPRI Electric Power Research Institute EQ environmental qualification ERT event review team
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ESAS engineered safeguards actuation system
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FSAR Final Safety Analysis Report GL Generic Letter
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gpm gallons per minute HDFA heavy dummy fuel assembly HPSI
. high pressure safety injection ICAVP.
Independent Corrective Action Verificction Program IFl-inspector follow item
.INPO Institute of Nuclear Power Operators
.I JPM job performance measure LCO limiting condition for operation LER(s)
licensee event report (s)
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LOCA loss of coolant accident
I LORT licensed operator requalification training LPSI low pressure safety injection MEPL(s)
material, equipment, and parts list (s)
i NCR(s)
nonconformance report (s)
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non-cited violation l
NNECO Northeast Nuclear Energy Company-
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NOVP nuclear oversight verification plan NRR Nuclear Reactor Regulation NUREG Nuclear Regulation-OCA Office of Congressional Affairs OEDO Office of Ext.cutive Director for Operations PAO Public Affairs Office L
PDR Public Document Room
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PMMS production maintenance management system
PORC plant operation review committee PORV-power-operated relief valve
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QA'
quality assurance
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OC quality control-l
.RAC regulatory affairs and compliance 3,
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RBCCW -
reactor building closed cooling water RCS reactor coolant system RG Regulatory Guide RWST -
refueling water storage tank SDC
. shutdown cooling system SFP spent fuel pool
' SIAS safety injection actuation signal SIL-significant item list
.SPROC special procedure SWP plant service water TRM-Technical Requirements Manual TS(s)
technical specification (s)
-URl(s)
unresolved item (s)
VIO'
- violation
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