IR 05000245/1998207
| ML20249C698 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 06/19/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20249C689 | List: |
| References | |
| 50-245-98-207, 50-336-98-207, 50-423-98-207, NUDOCS 9807010056 | |
| Download: ML20249C698 (220) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION SPECIAL PROJECTS OFFICE Docket Nos.:
50-245 50-336 50-423 Report Nos.:
98-207 98-207 98-207 License Nos.:
~ icensee:
Northeast Nuclear Energy Company L
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l P. O. Box 128
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Waterford, CT 06385
Facility:
Millstone Nuclear Power Station, Units 1,2, and 3 j
Inspection at:
Waterford, CT Dates:
March 1,1998 - April 27,1998 I
inspectors:
T. A. Eastick, Senior Resident inspector Unit 1 l
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l D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, Senior Resident inspector, Unit 3 P. Cataldo, Resident inspector, Unit 1 S. R. Jones, Resident inspector, Unit 2 B. E. Korona, Resident inspector, Unit 3 J. Higgins, NRC Contractor, Brookhaven National Laboratory P. Bezler, NRC Contractor, Brookhaven National Laboratory J. Cadwell, NRC Contractor, Brookhaven National Laboratory A. Fresco, NRC Contractor, Brookhaven National Laboratory M. Subhudhi, NRC Contractor, Brookhaven National Laboratory D. Prevatte, NRC Contractor, Parameter, Inc.
L. L. Scholl, Reactor Engineer, Region 1 J. W. Andersen, Project Engineer, HQ j
S. K. Chaudhary, Senior Reactor Engineer, Region I N. J. Blumberg, Project Engineer, Region i
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D. A. Dempsey, Reactor Engineer, Region I (In-office review)
L. Peluso, Radiation Specialist, Region 1 J. C. Jang, Sr. Radiation Specialist, Region I Approved by:
Jacque P. Durr, Chief Inspections, Special Projects Office, NRR i
9807010056 980619 PDR ADOCK 05000245 l
G PDR l
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I TABLE OF CONTENTS EX EC UTI VE S U M M A R Y............................................. iv i
U1.1 Operations
..................................................1 U101 Conduct of Operations............................... 1 l
U102 Operational Status of Facilities and Equipment.............. 1 U 1. Il M aint e n a n c e................................................. 3 l
l U1 M1 Conduct of Maintenance.............................. 3 I
U 1.Ill Enginee ring................................................. 4 l
l U1 E2 Engineering Support of Facilities and Equipment............. 4 f
l U1 E7 Quality Assurance in Engineering Activities................. 6 I
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U2.1 Operations
..................................................8 j
U2 01 Conduct of Operations............................... 8 j
U2 03 Operations Procedures and Documentation................. 9 U 2. ll M aint e na nc e................................................ 12
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U2 M1 Conduct of Maintenance.............................
l U2 M8 Miscellaneous Maintenance issues.....................
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U 2. lli Engine ering................................................ 2 3 j
U2 E8 Miscellaneous Engineering issues....................... 23 l
U3.1 Operations
.................................................32 U3 01 Conduct of Operations.............................. 32 U3 03 Operations Procedures and Documentation................ 33 U3 07 Quality Assurance in Operations....................... 40 U3 08 Miscellaneous Operations issues (92700)................. 42 U 3. ll M aint e n a n c e................................................ 4 8 U3 M1 Conduct of Maintenance............................. 48 U3 M2 Maintenance and Material Condition of Facilities and Equipment. 51 U3 M3 Maintenance Procedures and Documentation
..............56 U3 M8 Miscellaneous Maintenance Issues...................... 65 U 3. Ill En ginee ring................................................ 6 9 U3 El Conduct of Engineering................................... 69 U3 E2 Engineering Support of Facilities and Equipment............ 76 U3 E7 Quality Assurance in Engineering Activities................ 90 U3 E8 Miscellaneous Engineering issues....................... 95 IV Plant Support
................................................102 R1 Radiological Protection and Chemistry Controls............
102 il l
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R7 Quality Assurance in Radiological Protection and Chemistry Activities
.............................................104 F8 Miscellaneous Fire Protection issues..................
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V. Management Meetings......................................... 107 I
X1 Exit Meeting Summary.............................
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l EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined Inspection 245/98-207:336/98-207;423/98-207 l
Operations
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Licensee management adequately responded to a recently identified problem with
seal water flow on the Unit 1 SW pumps, resulting from a buildup of silt in the seal I
water lines. The activities associated with the underwater inspection of the SW l
intake structure were completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident.
(Section U1.02.1)
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At Unit 2, a review of procedures that are required by Technical Specification 6.8.1.a and Regulatory Guide 1.33 revealed that with the exception of the reactor coolant system, the licensee failed to establish instructions for draining the specified safety-related systems. This was characterized as a violation. Notwithstanding this violation, the licensee has taken significant steps in the last year to perform corrective actions identified in self-assessments. Although a recent NRC inspection identified concerns with alarm response procedures (ARPs) for the reactor building closed cooling water system, the review of selected ARPs for other systems did not
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identify additional concerns. The establishment of separate ARPs is a positive step.
(Section U2.03.1)
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At Unit 2, the NRC concluded that examples of inconsistencies between the operating procedures and the final safety analysis report (FSAR) raise questions regarding the comprehensiveness of the licensee's 50.54(f) review effort associated with operating procedures. Licensee management agreed to evaluate whether the discrepancies had been previously identified during their 50.54(f) review effort and if the discrepancies may have been introduced following the 50.54(f) effort, which would reflect upon the effectiveness of the procedure change process. The evaluation will be used to determine what additional reviews of operating procedures may be necessary. Unit 2 Significant items List No. 9 remains open to track licensee resolution of this issue. (Section U2.03.2)
The licensee's actions following the failure to comply with a Unit 3 technical
. specification (TS) upon initial entry into Mode 4 were appropriately scoped and performed. They ensured current compliance with Mode 4 TS and reviewed those i
TS which would be applicable in Mode 3. Through independent control board j
walkdowns and surveillance reviews, the inspector independently verified licensee compliance with selected Mode 3 TS. (Section U3.01.1)
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- lssues remain open regarding safety grade cold shutdown equipment controls.
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Clarification of the main steam atmospheric relief bypass valve and associated block valve technical specification is planned to delineate the effect of block valve operability on technical specification compliance. The inspector questioned the
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ability for Unit 3 to safely bring the plant to RHR initiation conditions in the time
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frame specified in the FSAR. (Section U3.03.2)
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NRC questions regarding the most limiting single failure assumption used in the Unit e
3 steam generator tube rupture (SGTR) analysis remain. Although the licensee demonstrated that the failure of a diesel was enveloped by the original analysis, it was concluded that the diesel may not have been the most limiting electrical failure for this event. A failure of other electrical equipment supplying power to either pair of main steam atmospheric relief bypass valves could be a more limiting failure not bounded by the current analysis. (Section U3.03.3)
Maintenance The removal and installation of lighting in the Unit 1 spent fuel pool in preparation e
for blackness testing, was well controlled. The implementation of radiological controls was successfulin reducing radiation exposure and preventing any personnel contaminations. Pre-job briefings continue to be a strength for the HP department.
(Section U1.M1.1)
e The licensee's performance of the overspeed test on the Unit 1 gas turbine was good. In addition, during the pre-job brief the licensee staff had a good questioning attitude regarding test termination criteria that contributed to the overall preparedness for the test. (Section U1.M1.2)
e At Unit 2, the failure to establish adequate isolation and the necessary plant conditions to support removal of discharge piping for a high pressure safety injection system relief valve resulted in two small spills of contaminated water. The number of errors that occurred during this event is cause for NRC concern.
However, the NRC concluded that corrective actions were appropriately directed and observed strong management interest in addressing the apparent misunderstanding of management performance expectations. In addition, operators have an extended track record of very good performance in establishing tagout isolation boundaries. Accordingly, this tagout violation was characterized as a Non-Cited Violation. (Section U2.M1.2)
e At Unit 2, during a fill of the low pressure safety injection system, due to the inadequate performance and review of a valve lineup, a vent valve was not closed resulting in a one-gallon spill of water that contaminated a plant equipment operator. The failure to adequately perform the valve lineup as specified in the operating procedure was characterized as a Non-Cited Violation. (Section U2.M1.3)
e At Unit 2, the licensee failed to adequately implement the reactor building' closed cooling water (RBCCW) operating procedure when an RBCCW valve was placed in service before operability of the valve was established though post-maintenance testing which contributed to the temporary loss of RBCCW system. This concern, i
which was not identified in the licensee's root cause investigation, was l
characterized as a violation. The opening of this RBCCW valve, which was
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providing RBCCW facility separation, was caused by a solenoid miswiring resulting from the incorrect transfer of lifted lead markings from the original to the replacement solenoid, in the violation response the licensee is asked to address the v
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adequacy of their procedural controls with respect to the requirement for independent verification for lifted leads. (Section U2.M8.1)
For Unit 2, the failure to test the four digital liquid and gaseous effluent radiation e
monitors in a manner consistent with the technical specification definition for a Channel Functional Test was considered a violation. At Unit 3, the test method for performing the channel functional test of the digital radiation monitors also failed to satisfy the corresponding technical specification definition. However, Unit 3 had I
already identified this concern had implemented corrective actions and therefore, the issue was characterized as a non-cited violation. (Section U2.M8.2)
The licensee failed to ensure that degraded or nonconforming parts were promptly e
identified and corrected in the area of nonsafety-related parts upgrade as part of the MEPL program. Specifically, although previous industry information had beer, issued in this regard 29 safety related Unit 3 components had nonsafety related l
parts procured and installed in the past two years. (Section U3 M3.1)
I The various aspects of the Unit 3 vendor interface program, as outlined in NRC e
Generic Letter 90-03 and the licensee's procedure DC 16, have been satisfactorily reviewed with the exception of the final review and updating of procedures to
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address vendor manual changes made during the vendor manual update process.
This aspect of the program upgrade had not yet been completed by the licensee by the end of the inspection period. (Section U3.M8.1)
Engineering e
The licensee's response to the Unit 1 gas turbine generator tachometer failure event was considered good, and culminated in the timely return of the gas turbine to available status. However, the licensee has not evaluated all available data in their determination and acceptance of a root cause and subsequent corrective actions regarding the tachometer generator failures that have occurred. Specifically, the inspector concluded that the common root cause for two prior tachometer failures, i.e., vibration over the life of the generator, was not substantiated by the vendor-supplied failure analysis reports for the August 1995 and January 1998 failures.
I This issue is considered unresolved pending completion of the licensee's root cause
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analysis of the April 1998 tachometer failure. (Section U1.E2.1)
e At Unit 1, the inspector identified a violation of 10 CFR 50, Appendix B, Criterion Vil, that required the licensee to establish measures that assured gas turbine generator fuel oil conformed to the procurement documents, and that documentary evidence was available prior to use in the gas turbine. The inspector also identified i
various procedural compliance issues and these should be addressed by the licensee
in the response to this violation. In adoition, the licensee should address the
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generic implications raised by this violation as they relate to diesel generator fuel oil l
across all three Millstone units. (Section U1.E7.1)
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At Unit 2, the proposed revision to the final safety analysis report provided in the licensee's September 3,1S97, submittal contained incomplete information regarding
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their ability to replenish the fuel oil supply tanks for the emergency diesel generators. This was characterized as a violation of 10 CFR 50.9. (Section U2.E8.1)
The licensee has been working on the Unit 2 Material, Equipment, and Parts Lists
(MEPL) program for the last two years and has performed many evaluations that begin to address the MEPL concerns. However, several previous reports, including the cover letter for NRC Inspection Report 50-336/97-208, highlighted the concern that the licensee has not yet fully developed broader corrective actions to address past instances where nonsafety-related (NSR) components and parts were inappropriately installed in safety-related systems (e.g., for parts that were classified as " Undetermined" or "NSR" and had no MEPL evaluations). During this inspection period, the NRC found that the licensee has still not approved an acceptable plan to address this concern. Therefore, at the exit meeting held on May 1,1998, the NRC requested and the licensee committed to provide to the NRC by May 15,1998, a letter describing their plan for dispositioning these MEPL concerns. (Section U2.E8.2)
Based on an NRR review of documentation for modifications made to the Unit 3 RSS system, field walkdown of the system, and discussions with the licensee, the NRC determined that modifications made to the RSS during the current outage appear to be in compliance with the requirements of 10CFR50.59. An unreviewed safety question was identified by the licensee concerning the 1986 removal of RSS direct injection to the reactor coolant system. (Section U3.E2.1)
The inspectors concluded that licensee evaluation of items for deferral until after the Unit 3 restart was generally appropriate and reflected a conservative decision-making process. None of the items questioned by the inspectors would have resulted in a significant impact on safe plant operation if they had actually been resolved after plant restart. Although several minor, generally administrative errors were identified, the inspectors concluded that the accuracy and completeness of the deferred issues list was sufficient. (Section U3.E7.1)
Plant Support
The licensee effectively maintained and implemented a radiological environmental monitoring program in accordance with regulatory requirements. (Section R1.1)
The inspector identified that the. licensee failed to measure the instrument minimum accuracies for the wind speed chEnnels, as required by Table 3.3-8 of the Unit 2 Technical Specification 3/4.3.3.4, constituting a violation of regulatory requirements. (Section R1.2)
The licensee identified that SORC failed to review and approve the calibration procedures (wind speed, wind direction, and delta temperature) for the meteorologicalinstrumentation, as required by TS 6.5.2.6 a. This licensee-identified and corrected violation constitutes a Non-Cited Violation. (Section R1.2)
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l The licensee met the QA audit requirements. The audits were thorough and of
- sufficient depth to assess the strengths and weaknesses of the REMP and MMP.
(Section R7.1)
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The contractor laboratory continued to implement excellent QA/QC programs for the
REMP, and continued to provide effective validation of analytical results and the programs are capable of ensuring independent checks on the precision and accuracy of the measurements of radioactis e materialin environmental media. (Section R7.2)
The inspector reviewed corrective actions for a previously identified violation and
performed additional inspection of a previously identified inspector follow-up item.
The previously identified violation will be closed, based on review of implementation of corrective actions and the inspector follow-up item will be closed, based on review of additionalinformation developed by the licensee. At the conclusion of this inspection there were no open items in the area of security. (Section S8)
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Report Details Summarvof Unit 1 Status Unit 1 remained in an extended maintenance mode for the duration of the inspection period. Personnel focused their efforts on performing corrective and preventative maintenance in order to maintain the plant in a safe shutdown condition.
U1.1 Operations U101 Conduct of Operations 01.1 General Comments (71707)
Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. Control room panel walkdowns were performed to identify whether significant plant parameters and indications wera at expected values for current plant conditions; whether any significant trends existed, as noted in Section 02.1; or whether the safety and risk significant systems including their support systems were appropriately aligned and available. The inspectors conducted inspection-tours of equipment in the various plant buildings. The inspectors observed operational protocol, procedural adherence, and the control of shutdown risk. In general, the conduct of operations was professional with an appropriate focus on shutdown risk. The inspectors also attended the licensee #s plan of the day meetings, and other meetings as appropriate to obtain the overall status of the plant and of the licensee's activities that were planned or in progress.
Noteworthy observations are detailed in the sections below.
U102 Operational Status of Facilities and Equipment O2.1 Service Water Pumos a.
Insocction Scope (71707)
In March of 1998, as a result of daily control room tours, the inspector noted an increase in the number of service water (SW) pump shifts (stopping one pump and starting another)
due to low seal water flow to the standby SW pump. The apparent cause of the low seal water flow was a buildup of silt in the SW system. The inspector reviewed the licensee's response to the silt issue, which included an underwater inspection of the SW intake structure by divers.
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Observations and Findinas Under the current plant configuration, only one SW pump is necessary to supply adequate cooling to the plant's heat loads. In accordance with the operating guidance, if the seal water flow to the standby pump decreases below 2 gpm, that pump should be declared unavailable for service. However, the current operating practice is to start the standby pump when seal water flow has decreased to the 2 gpm limit. This action results in
" blowing-out" the seal flow line due to increased SW pump discharge pressure, and as a result, restores seal flow to the upper part of the normal 2-5 gpm band.
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in early March, the inspector noted an increased frequency of SW pump shifts and i
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requested the operations staff to perform a review of the control room logs to determine if there was an increasing trend in the number of pump shifts. The results of that review indicated that for the past year, the pumps were shifted once or twice per month until February of 1998. The number of pump shifts increased to nine for the month of February and seven for the rnonth of March. Also during this time period, two condition reports (CRs) were initiated that documented the presence of silt found in sensing lines for SW flow instrumentation, as well as a buildup of mud and silt discovered in the seal water strainer. On March 18,1998, operations issued a Briefing Sheet discussing the potential for silt fouling in the SW system. The Briefing Sheet heightened operator awareness about the potential for degraded seal water flow, erroneous system indication, and degraded heat exchanger performance, in particular during the operation of the emergency diesel generator.
In response to this issue, Unit 1 management determined that an inspection of the intake structure was needed to verify the condition of the bays. The inspector attended a planning meeting on March 19,in preparation for the divers' inspection of the intake bays.
During the meeting, operation, maintenance, and engineering performed a comprehensive review of the planned activities and discussed the requirements for the divers to safely enter the intake structure. Security and health physics (HP) support was requested, as well as a review of industry events for diving related accidents.
The inspector observed the underwater inspection on March 26,1998. During the pre-job briefing, both the maintenance supervisor and the HP technician briefed the work group.
The briefs were detailed and comprehensive with personal safety emphasized throughout the discussion. Plant management and nuclear oversight were present for both the pre-job briefings and the inspections. During the inspections, one diver was in the water and two other qualified divers acted as support and safety personnel.' HP technicians provided foreign material exclusion (FME) area support during the dives to ensure that no foreign material entered the intake bay while they were open for the inspection. The FME zone was moved from bay to bay as the inspections were completed. An emergency medical technician was present for the entire evolution. In addition to the visual inspection, the diver measured the sitt layer at the bottom of each bay. The inspections of the five bays were well coordinated and efficiently managed. All work observed was performed with the work package present and in active use. The inspector noted that as the work progressed, workers exhibited a good questioning attitude. The inspections were completed without incident and an underwater videotape recording was made during the inspection.
The inspector reviewed the videotape after the inspection and discussed the results with the maintenance manager. The A, B, C, and D bays had a foot or less of silt buildup on the floor, with approximately 3-8 inches of seaweed on top of it. The "E" bay had a silt depth of 28-39 inches towards the back of the bay. (The intake for the SW pumps is 11 feet from the bottom.) In all bays, marine growth was observed and attributed to the low flow condition, since only one SW pump is in service at a time. The "E" bay contains the A & B SW pumps, as well as the four emergency service water (ESW) pumps. CR M1-98-0270 was initiated to document the extensive marine growth on the ESW pumps, which in the current plant configuration, are not required to be operated. The fouling on the ESW
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pumps will need to be further investigated and the growth removed prior to running the pumps.
l The licensee concluded that the silt in the SW system is most likely due to storm-induced wave action that periodically brings the silt into the intake structure and also stirs up the existing silt on the floor of the bays. Engineering is monitoring the correlation between specific weather conditions that appear to coincide with frequent instances of low seal water flow. Engineering has also provided direction to the operations staff that if the SW pumps are shifted more than five times per month to correct a low seal flow condition on the standby pump, then the seal water lines should be cleaned as soon as practical. At the end of the inspection period, the licensee was continuing their review of the sitt problem.
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Conclusions Licensee management adequately responded to a recently identified problem with seal water flow on SW pumps, resulting from a buildup of silt in the seal water lines. The activities associated with the underwater inspection of the SW intake structure were completed thoroughly and professionally. A well-coordinated effort by plant staff allowed the inspections to be completed without incident.
U1.ll Maintenance.
U1 M1 Conduct of Maintenance M 1.1 Removal and Installation of Liahtina in the Spent Fuel Pool a.
Inspection Scoce (62703)
The inspector observed activities during the removal and installation of lighting in the Unit 1 spent fuel pool. This work was performed in preparation for blackness testing, which is a method used to measure thermal neutron attenuation in the wall of the spent fuel storage racks that utilize Boraflex as a neutron absorber material.
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Observations and Findinas On April 24,1998, the inspector observed a pre-job briefing conducted by the health physics (HP) department. The scope of the work was clearly defined and hold points in the work process were described that facilitated HP surveys of equipment being removed from the spent fuel pool. The radiation work permit was reviewed, including the need for face shields and plastic overalls for all workers who would be in direct contact with the lighting as it was removed from the pool. Previous industry events concerning work in the spent fuel pool were also reviewed by the HP manager.
During the actual work, four older-style lights were removed from the fuel pool and properly bagged and stored for later maintenance work. Three high-power sodium lights were placed in the fuel pool to provide adequate lighting in support of blackness testing.
The work was coordinated by reactor engineering with the assistance of HP technicians.
The inspector observed that all work was performed under an approved automated work
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order and proper radiological practices were followed. Additionally, the appropriate foreign material exclusion controls were in place for all work in or around the spent fuel pool.
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Conclusions The removal and installation of lighting in the spent fuel pool in preparation for blackness
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testing was well controlled. The implementation of radiological controls was successful in reducing radiation exposure and preventing any personnel contaminations. Pre-job i
briefings continue to be a strength for the HP department.
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' M1.2 Gas Turbine Generator Oversoeed Test a.-
j.nsoection Scone (62703)
The inspector observed licensee performance of the gas turbine generator overspeed test which was accomplished in accordance with SP 668.17, " Gas Turbine Overspeed Test."
The test was conducted to support the return of the gas turbine following the tachometer failure event which had occurred in April 1998.
b.
Observations and Findinos
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The licensee conducted a pre-job brief with the applicable staff.and discussed test.
objectives, basic procedure steps, as well as specific termination criteria. Industry events and past operating history were also discussed as they relate to the performance of overspeed tests on emergency generators, in addition, operator feedback and questions were provided by a number of licensee personnel. The overspeed test was performed and the replacement tachometers operated within the guidelines of both the troubleshooting plan and the overspeed test. 'Following the overspeed test, the inspector verified that the monthly surveillance run was performed and the unit was returned to available status in the current shutdown plant condition.
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Conclusions The inspector concluded the licensee's performance of the overspeed test was good. In addition, during the pre-job brief the licensee staff had a good questioning attitude regarding test termination criteria that contributed to the overall preparedness for the test.
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U1 E2 Er.girc:ir.g Support of Facilities and Equipment E2.1 Gas Turbine Generator Tachometer Failure and Replacement a.
~lnsoection Scope (37551)
Condition report (CR) M1-98-0289 was initiated by the licensee on April 8,1998, and
- described an emergency gas turbine generator (GTG) event that resulted in a manual trip of the unit. Subsequently, the inspector evaluated the initiating corsdition as well as various
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licensee corrective' actions following the event, which ultimately led to replacement of the tachometers and the return of the GTG to an available status, b.
Observations and Findinas During performance of a monthly surveillance run on the GTG using SP 668.2, " Gas l
Turbine Emergency Fast Start," the Unit Supervisor in the control room observed 2 MWe load swings on the panel indications within approximately 20 seconds and the control room operator subsequently tripped the unit as directed by the procedure. Within a short time, the Unit.1 Director had mobilized an event team comprised of management and support personnel to assist in the investigation of the event.
The licensee identified a potential cause of the GTG oscillations based on interviews, initial evaluation of recorded data, GTG response exhibited both during and following the event, and historical data available from a previous tachometer failure. The cause of the event.
was attributed to a similar failure of the backup overspeed tachometer which had occurred in January 1998; loss of the output speed signal. The most recent failure, however,
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exhibited fluctuations consistent with the output signal from the tachometer to the
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woodward governor speed control circuit.
The licensee's event team developed a repair plan.that replaced the two tachometers that
_ i were installed on the GTG (the backup overspeed unit and the woodward governor speed control unit) with units refurbished by a local repair vendor under an approved 10 CFR 50, Appendix B quality assurance program. The refurbished units consisted of original tachometer housings with stators purchased from a replacement vendor for the original equipment manufacturer (OEM). The repair vendor identified two deficiencies during the refurbishment: (1) spring washers (for bearing pre-loads) were installed contrary to the original equipment drawings as well as in'dustry experience, and (2) out of tolerance bearing clearances. These two concerns were addressed through refurbishment as the spring washers were installed with the correct orientation and new bearing assemblies -
were installed in the tachometers. The refurbished tachometers were installed on the GTG, i
. were tested satisfactorily during an overspeed test surveillance procedure, and the GTG j
was successfully returned to available status after the normal monthly surveillance run.
j Subsequent to the return of the GTG to available status, the inspector evaluated root cause j
determinations that were based on failure analysis reports performed by the repair vendor
- for an August 1995 failure and a January 1998 failure. The 1995 failure analysis report for the backup overspeed tachometer stated in part, the root cause of the physical failure
.l of the stator is attributed to normal degradation of the wire due to vibration during the life I
of the generator...but the primary mode of failure was stress fracture due to the vibrations I
- encountered during the 16 years of operation based upon review of purchasing documents.
However, the inspector reviewed various procurement and other licensee records as well as the 1994 design change package that installed the backup overspeed tachometer, and
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determined the tachometer operated for approximately 1 year prior to the failure in 1995.
l The January 1998 failure analysis report for the backup overspeed tachometer also stated,
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in part, the root cause of the physical failure of the stator is attributed to normal
. degradation of the wire due to vibration during the life of the generator...but the primary j-a_
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I mode of failure was surmised to be due to the vibrations and normal wear and tear I
encountered during the extended years of operation. Prior to the January 1998 failure, the backup overspeed tachometer operated for approximately two and one-half years from the time it was installed as a replacement for the earlier 1995 failure. In addition, in 1994 the power turbine as well as the high speed coupling for the GTG was replaced and eliminated a vibration concern that was previously identified by the licensee. The recent April 1998
- failure, which occurred at the speed control location versus the backup overspeed location, exhibited similar failure characteristics as the January 1998 failure. The licensee intends to
- have the repair vendor perform a failure analysis in the near future to determine a root cause for the April 1998 tachometer failure.
c.
Conclusions
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The licensee's response to the gas turbine generator event was considered good, and -
culminated in the timely return of.the gas turbine to available status. However, the licensee has not evaluated all available data prior to their determination and acceptance of a root cause and subsequent corrective actions regarding the tachometer generator failures that have occurred. Specifically, the inspector concluded that the root cause for the tachometer failures, i.e., vibration over the life of the generator, was not substantiated by the vendor-supplied failure analysis reports for the August 1995 and January 1998 failures. This issue is considered unresolved pending completion of the licensee's root
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cause analysis of the April 1998 tachometer failure. (URI 50-245/98-207-01)
U1 E7 Quality Assurance in Engineering Activities E7.1 (Closed) Unresolved item (URI) 50-245/97-208-01: Gas Turbine Generator Fuel:
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Ooen VIO 50-245/98-207-02 a.
Inspection Scone (92903)
Condition report (CR) M1-97-2525 was initiated by the licensce on December 11,1997, i
and described that fuel oil for the emergency gas turbine generator (GTG) that had been I
delivered and used for several years, was ASTM D-3699 K-1 Kerosene versus ASTM D-1655 Jet A-1 aviation fuel as required by the applicable purchase order. The inspector evaluated the initiating condition as well as a number of the licensee's corrective actions.
In addition, the inspector reviewed various procedural controls established by the licensee for ensuring the quality of the gas turbine fuel as required by the licensee's quality assurance program (QAP). ;
_
- b.
. Observations and Findinas The licensee's current revision to the QAP section 7.0, " Control of Purchased Material, Equipment and Services," requires that receipt inspection for procured items be performed by Procurement Quality Services (currently referred to as Nuclear Receiving Group (NRG))
in accordance with quality procedures, and that fulfillment of contractual obligations and
'
specified requirements are verified during receipt inspections. One exception to this requirement, however, is that the chemistry department will perform receipt inspections for
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l diesel fuel. This exception was introduced as a change to the QAP effective with the current Revision 18 dated August 15,1995.
While GTG fuel oil is not specifically identified in the QAP as a fuei that requires receipt inspection, it appears in Appendix A of Northeast Utilities (NU) QAP as a consumable, and therefore, is subject to the quality assurance requirements of the applicable portions of the QAP. Based upon the review of various licensee implementing procedures and documents relative to the control of purchased material (i.e., GTG fuel oil), the inspector identified the following:
While NRG performed receipt inspections on GTG fuel as required (pre-1995), they a
failed to identify that kerosene was not the fuel required by the purchasing documents. For example, a bill of lading (delivery record) dating as far back as 1985, identified No.1 Fuel Oil (Kerosene) as the fuel delivered for use, versus the required Jet A-1 fuel. Another example was a maintenance receipt inspection report (MRIR) from May of 1992, that contained a bill of lading that identified kerosene as the shipped product, as well as numerous references to the purchase order that lists aviation turbine fuel ASTM D 1655, type Jet A-1 as the requested fuel.
While the current revision to the QAP incorporated the exception regarding the
chemistry department performing receipt inspections on diesel fuel only, chemistry was performing sample analyses on the GTG fuel oil as well (post-1995). However, they failed to identify that kerosene was not the fuel required by the purchasing documents. In addition, a chemistry procedure, which details the specific sampling and analysis requirements during the receipt of GTG fuel oil, specifically instructs the technician to verify that the bill of lading matches the sample requested for kerosene.
Fuel oil samples have been sent off-site to an NU facility for testing, which is not
covered under the NU QAP. Station procedures do not currently address this method of analysis. Moreover, current procedures only address testing by an NU facility that is covered under the NU QAP.
Post-1995. maintenance receipt inspection reports (MRIR) were not being generated
as required by station procedures.
In 1995, NRG initiated a change to the purchase order for the procurement of GTG
fuel oil that removed their responsibility for performing receipt inspections; the change order placed requirements for acceptance onto a common operating procedure that identified fuel oil delivery sampling requirements and contained no reference to receipt inspection or commercial grade dedication requirements set forth by the previous purchase order. As a result, OA receipt inspections were not being performed in accordance with station procedures. Recently however, the licensee revised C OP 600.5 " Fuel Oil Delivery Sampling Requirements" to include references to required receipt inspection activities. The inspector subsequently verified that the licensee began to document and perform receipt inspections for a May 13,1998, GTG fuel oil delivery.
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In 1996, commercial grade dedication requirements were transferred to a computer-
based system, Materials information Management System (MIMS). The licensee could not produce documentation that would indicate commercial grade dedications were being performed and documented in accordance with station procedures since the program's inception.
. Criterion Vil of 10 CFR 50, Appendix B, states in part, that measures shall be established to assure that purchased material conforms to the procurement documents, and documentary evidence that material conforms to the procurement requirements shall be available prior to use of such material. Contrary to the above, as far back as May of 1992, the licensee failed to assure that fuel oil delivered and used for the GTG conformed to procurement documents, and between 1995 until a GTG fuel oil delivery on May 13,1998,
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the licensee failed to document in maintenance receipt inspection reports that the fuel oil
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conformed to the procurement documents prior to its use. This constitutes a violation of 10 CFR 50, Appendix B, Criterion Vll. (VIO 50-245/98-207-02). As a result, URI 245/97-208-01 is considered closed.
c.
Conclusions
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The inspector identified a violation of 10 CFR 50, Appendix B, Criterion Vil, that required l
l the licensee to establish measures to assure gas turbine generator fuel oil conformed to i
procurement documents, and that documentary evidence was available prior to use in the -
gas turbine. The inspector also identified various procedural compliance issues and these
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should be addressed by the licensee in the response to this violation. In addition, the licensee should address the generic implications raised by this issue as they relate to the purchase, testing and use of diesel generator fuel oil at all three Millstone units.
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Report Details p
Summarv of Unit 2 Status Unit 2 entered the inspection' period with the core off-loaded. The unit was initially shut n
down on February 20,1996, to address containment sump screen concerns and has
- remained shut down to address the problems outlined in the Restart Assessment Plan and an NRC Demand for Information [10 CFR 50.54(f)]Ietter requiring an assertion by the
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licensee that future operations are conducted.in accordance with the regulations, the L
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license, and the Final Safety Analysis Report.
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U2.1 Onorations LU201 Conduct of Operations
- 01.1 - General Comments (71707)
Using inspection Procedure 71707,the inspectors' conducted frequent reviews of ongoing plant operations.~ Observed shift turnovers have been clear and thorough. In particular,
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the inspectors noted good sensitivity to special evolutions and any work that could affect shutdown safety equipment. Operations management has demons + rated interest in the conduct of shift turnovers by frequent observation.
U2 03 Operations Procedures and Documentation O 3.1 Procedure Uoorade Proaram for Unit 2 (Update Unit 2 Significant items List No. 81 a.
jngoectior' Scope (427QQ)
The inspector reviewed the overall status of the Ur.it 2 Procedure Upgrade Program (PUP)
with a particular focus on alarm response procedures, in addition, the inspector also a
reviewed a sampling of licensee procedures to evaluate whether the procedures required by Technical Specification 6.8.1 and Regulatory Guide (RG) 1.33, Appendix "A", have been established.
b.
Observations and Findinas To address Unit 2 Significant items List No. 8, in April 1997, the licensee had a contractor perform an assessment to evaluate their compliance to RG 1.33, Appendix "A". This
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assessment determined that the licensee had a procedure established for all procedures listed in RG 1.33. This assessment also identified 16 major weaknesses in both procedure implementation and procedure adequacy. On a sampling basis, the inspector reviewed some of the corrective actions taken following this self assessment:
Finding - Administrative procedures were identified as fragmented and difficult to
use.
Corrective Action - The licensee now has in place an active process to upgrade, simplify, and re-categorize station administrative procedures; a committee has been established for accomplishing these tasks. Also, procedure SPROC 98 S 1,
" Developing Program Descriptions for Administrative Process," is currently in use for improving the administrative procedures.
Finding - Methods were not in place for ensuring procedures were complete and
accurate.
Corrective Action - The configuration management program has been completed per procedure U2 Pl 7. Unresolved items (URis) as a result of this process identified procedure deficiencies that are currently being reworked.
Finding - Procedures were inadequate at the time of use and procedure compliance
does not meet industry standards.
Corrective Action - In October 1997, procedure DC-4, " Procedural Compliance,
was extensively revised. There was a work stand-down to conduct training for this procedure. Performance indicators snow improvement in both procedure performance and technical adequacy. In addition, system engineers are performing
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a 100% review of surveillance test procedures to ensure that all surveillance tests are technically adequate. The inspector reviewed documentation that this has been completed for Modes 5 and 6 surveillance tests. Modes 3 and 4 surveillance tests are currently under review.
Finding - The biennial review process does not seem to be effective.
- Corrective Action - Procedure DC-1, " Administration of Procedures and Forms," has been revised to improve the procedure biennial review process.
The inspector also performed a sampling review of procedures required by RG 1.33. RG 1.33, Appendix "A", Paragraph 3, " Procedures for Startup, Operation, and Shutdown of Safety-Related [ Pressurized Water Reactor) PWR Systems," states that instructions for energizing, filling, venting, draining, startup, shutdown, and changing modes of operation, should be prepared, as appropriate, for the systems listed. The inspector found that with
the exception of the reactor coolant system, procedures for draining safety-related systems
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have not been established (i.e. prepared and approved by the Plant Operations Review Committee (PORC) or a Station Qualified Reviewer (SOR)). The licensee had been utilizing a generic procedure, OP 2265," Requirements for Draining and Filling Activities," Revision 0, to fulfill the RG 1.33 requirement. The failure to establish the draining procedures required by RG 1.33 would have been mitigated by procedure 2265, but the inspector found that the licensee was not following the instructions provided in this procedure.
Procedure OP 2265 authorizes the establishment of non-PORC approved procedures for non-complex evolutions. Although this procedure requires the evaluation for determining if PORC review of a proceduro is required, the inspector found that complex system draining procedures, as many as eight pages in length, had been used with no review or approvals above the shift manager level. Some examples were: (1) Draining of the Facility 11
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Refueling Water Storage Tank Suction Header; (2) Draining of Piping Between Valves 2-SI-442 and 2-RW-11; and (3) Draining of Common Suction and Discharge Headers of the Low Pressure Safety injection System. Technical Specification 6.8.1.a requires that written procedures be established for the applicable procedures recommended in Appendix "A" of RG 1.33, which in turn requires instructions for draining the specified safety-related systems. The f ailure of the licensee to establish procedures for draining the specified safety-related systems, with the exception of the reactor coolant system, is considered a violation. (VIO 50-336/98-207-03)
The inspector also reviewed a sampling of alarm response procedures (ARPs) to evaluate whether problems with ARPs noted in NRC Inspection 50-336/98-202was more wide spread. NRC inspection 50-336/98-202,which documents an in-depth review of the reactor building closed cooling water (RBCCW) system, noted inconsistencies between the RBCCW system ARPs and Abnormal Operating Procedure (AOP) 2564, " Loss of RBCCW."
In the sample of additional ARPs, the inspector noted severalinstances where there was a small overlap between steps in the ARP and steps in the AOP. ?n these cases no inconsistencies were observed. The inspector also found that the information contained in the ARPs was consistent with the guidelines of RG 1.33, Appendix "A". If immediate actions did not correct the alarm condition, then the operator is referred to an OP, EOP or AOP as appropriate. The original ARP problem noted in NRC inspection 50-336/98-202 l
appeared to be limited to the RBCCW system.
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11 On March 31,1998, the licensee generated Condition Report (CR) M2-98-0880 to document the RBCCW ARP concerns. Although CR M2-98-0880 has not yet been closed, the licensee's planned corrective actions include: (a) In the short term, the RBCCW System ARPs will be reviewed and changes made to ensure consistency with the actions identified in procedure AOP 2564; and (b) In the long term, the Centralized Procedures Group plans to develop and review ARPs together with referenced AOPs or Emergency Operating Procedures (EOPs) to ensure the subject procedures are consistent. The licensee stated that they plan to complete this review by the end of 1999 and they do not consider it a startup issue. The licensee also stated that where ARPs and AOPs must partially overlap, the basis document will be the mechanism to ensure that if changes are required to one procedure the other will be reviewed to ensure consistency between procedures.
The inspector also reviewed the alarm response procedures in relationship to the procedure upgrade program. Prior to the PUP, all ARPs were maintained as a separate paragraph within applicable system operating procedures (ops) rather than being a separate procedure. The Control Room Alarm Book (CRAB) listed each alarm and referenced the applicable OP. As part of the PUP, the licensee has been removing the ARPs from the ops and establishing separate procedures; the CRAB has been updated accordingly. At the time of this inspection, approximately 85% of the ARPs have been separately established.
Upon completion of the PUP, each annunciator will have a stand alone ARP associated with it, and the CRAB will be eliminated.
Regarding all Unit 2 procedures, the licensee has 77 procedures remaining to be upgraded for completion of the PUP. General programmatic findings regarding the PUP at Unit 3 have been previously detailed in NRC Inspection Reports 50-423/97-01 and 50-423/97-203. These findings are also applicable to Unit 2 as the program and its implementation were sitewide in its application. Ongoing NRC reviews of the technical adequacy of Unit 2 procedures are being conducted as part of the Independent Corrective Action Verification Process.
c.
Conclusions The inspector identified a violation of TS 6.8.1.a,in which the licensee failed to establish procedures for draining safety-related systems. The licensee has taken significant steps in the last year to perform corrective actions identified in recent self-assessments. Although a recent NRC inspection identified concerns with alarm response procedures (ARPs) for the RBCCW system, the review of selected ARPs for other systems did not identify additional concerns. The establishment of separate ARPs is a positive step.
03.2 Operatina Procedures Reflectina Final Safety Analysis Reoort (Update - Unit 2 Significant items List No. 91 a.
Insoection Scope (71707)
The inspector evaluated the licensee's progress in addressing Unit 2 Significant items List No. 9 which addresses operating procedures not reflecting the final safety analysis report (FSAR). It also addresses the effectiveness of the licensee's procedure change process in ensuring procedure changes are reviewed against the FSA. - _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
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b.
Observations and Findinas Several recent examples have been identified by the NRC and licensee where operating procedures did not reflect the FSAR. A recent example was identified and cited in NRC Inspection Report 50-336/98-202concerning the RBCCW system. Two more examples were identified during this inspection as noted below:
(1) The inspector noted that FSAR Section 6.3.3.1 discusses placing the key-lock switches to " operate," to enable closing the isolation valves for the recirculation lines back to the refueling water storage tank following a sump recirculation actuation signal (SRAS).
The FSAR states that the key-lock switches are placed in " operate" followina an SRAS while procedure EOP 2532, " Loss of Primary Coolant," specifies placing the switches to
" operate" orior to an SRAS. This discrepancy had been previously noted by Parsons Power Group incorporated.
(2) A number of condition reports (CRs) have been initiated since the completion of the 50.54(f) " discovery" that also raise questions regarding FSAR consistency with operating procedures. During this inspection period, CR M2-98-112Owas generated that describes valve position discrepancies for several valves specified in the FSAR. Additionally, CR M2-98-1021 discusses a discrepancy between procedure OP 2347A," Reserve Station Service Transformer (RSST)," and the FSAR. OP 2347A states that the maximum total current
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from the RSST to Buses 25A & 25B should be less than 2250 amps, and to Buses 24C &
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24D should be less than 2500 amps. The FSAR states that these buses have a 2000 amp continuous duty rating.
c.
Conclusion The NRC concluded that examples of inconsistencies between'the operating procedures and the FSAR raise questions regarding the comprehensiveness of the licensee's 50.54(f)
l review effort associated with operating procedures. Licensee management agreed to I
evaluate whether the discrepancies had been previously identified during their 50.54(f)
review effort, or if the discrepancies may have been introduced following the 50.54(f)
effort, which would reflect upon the effectiveness of the procedure change process. The i
evaluation will be used to determine what additional reviews of operating procedures may be necessary. Unit 2 SIL No. 9 remains open to track licensee resolution of this issue. The FSAR discrepancies described in examples (1) and (2) above are considered violations of minor significance and are not subject to formal enforcement action.
U2.ll Maintenance U2 M1 Conduct of Ma!ntenance M 1.1 General Maintenance Observations a.
Insoection Scone (61726)
The inspector observed all or part of work activities performed under the following automated work orders (AWOs):
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M2-98-02252 Disassemble \\ Reassemble Valve 2-CS-16.1B(Containment
Sump Recirculation isolation Valve) for inspection and Determination of High Thrust Loads when Valve is Stroked M2 98-02773
"B" Low Pressure Safety injection Pump Overhaul
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M2 98-03124 Correct Vibration on Lower Bearing of "B" Low Pressure Safety injection Pump Motor b.
Observations and Findinas i
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The inspectors found the work performed under these AWOs to be professional and i
thorough. The AWO was present at the work site and the ma;ntenance workers were f
experienced. Maintenance supervisors were frequently present and monitoring work l
progress. Appropriate radiological and foreign material exclucion controls were in place.
M1.2 Eauioment Drain Sumo Tank Spill Due to inadeauate isolation a.
Insoection Scone (62707_)
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The inspector reviewed the circumstances surrounding the April 1,1998, spill of contaminated water from the equipment drain sump tank during maintenance activities to
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remove a section of piping, inspection activities included a review of documents related to the maintenance activities and interviews with personnel in the licensee's operations,
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maintenance, and work planning organizations.
b.
Observations and Findinas in April 1997, the licensee removed relief valve 2-SI-007 in the high pressure safety injection (HPSI) system for repair, and installed Temporary Modification 2-97-024 to isolate the upstream and downstream piping with blank flanges. After determining that the relief
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valve was not needed, a plant design change was prepared, and automated work order (AWO) M2-97-09994was generated to remove piping upstream and downstream of that va!ve. When preparing the tagout for this work, the Work Control Operator reviewed the AWO by reading the title, but did not sufficiently review the work package to obtain a complete understanding of the scope of the work. Consequently, tagging associated with the downstream side of the relief valve was not considered. However, isolation was i
needed to cut and remove the downstream piping because it ties into a shutdown cooling water system drain line, which then drains to the equipment drain storage tank (EDST).
Because the EDST is pressurized by other drain lines as well as the nitrogen level indication bubbler, actions to drain the EDST and isolate drain lines and the nitrogen level indicator was necessary to eliminate the EDST as a pressurized water source.
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Similarly, the Work Control Senior Reactor Operator (SRO) who approved the tagout and l
authorized the AWO also did not perform an adequate review of the work package to fully understand the work scope. Therefore, the AWO was released to maintenance with only the upstream safety injection side being isolated. Although the Work Control Operator and Work Control SRO were responsible for establishing adequate isolation for this work, there were additional opportunities to identify the error. As allowed by procedure WC 2,
" Tagging," the maintenance first line supervisor (FLS) delegated review of the work site l
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and evaluation of isolation boundaries to the assigned maintenance workers. Alth'ough the maintenance workers did not fully understand the system interface associated with the EDST, the FLS could have recognized the isolation problem. Another problem was that maintenance workers did not recognize the significance of the Temporary Modification tag hanging on the blank flanges where relief valve 2-SI-OO7 used to be located.
l A problem that was identified by the maintenance workers was that valve 2-CS-OO8A, an
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- isolation valve on the shutdown cooling system drain line' which was just beyond the
' planned cut, had not been tagged closed. The maintenance workers notified operations that valve 2-CS-OO8A had not been tagged, thereby providing operations another opportunity to identify that plant conditions and system isolation had not been adequately established for this work. However, operators did not recognize any further problems and only tagged valve 2-CS-OO8A closed.' An additional error was that the maintenance
- workers began work after checking that valve 2-CS-OO8A was closed, but before
- operations tagged the valve.
When the workers cut the pipe during the evening of April 1,1998, water began to leak
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from the cut. ' In order to stop the spill of contaminated water, operations pumped a
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portion of the EDST contents to liquid radwaste. In addition, valves were closed in many of the lines that drained to or pressurized the EDST. Condition Report (CR) M2-98-0909 '
was generated to document the spill.
. The operations staff initiated tagging efforts to provide full isolation of the cut pipe and EDST. However, during the morning of April 2,1998, before isolation of the EDST was completed, all new work was halted to ensure that other open AWOs had adequate isolation. This work stand down caused a delay in completing isolation of the EDST.
j Meanwhile, the nitrogen supply to the EDST level indication, which was not isolated, pressurized the EDST and caused an additional small spill of contaminated water from the
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cut pipe. The spill was stopped when operations completed the isolation of the EDST
'during the evening of April'2,1998. This second spill was documented in CR M2-98-0931.
The licensee performed a thorough root cause of this event which identified the following
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factors as contributors to the spill: (1) poor coordination of the AWO for piping removal; (2) poor understanding of the AWO work scope; and (3) inadequate review of work area prior to beginning work. These factors contributed to the root cause, inadequate isolation
. of the work area. The licensee's corrective actions involve training regarding lessons learned from the event and emphasis of management expectations for implementation of the work control and tagging processes.' The inspector observed strong management interest in addressing the apparent misunderstanding of management performance
. expectations.
c.
Conclusions The failure to establish adequate isolation and the necessary plant conditions to support removal of discharge piping for a HPSI system relief valve resulted in two small spills of contaminated water. The number of errors that occurred during this event is cause for NRC concern. However, the NRC concluded that corrective actions were appropriately
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. directed and observed strong management interest in the corrective actions. In addition, operators have an extended track record of very good performance in establishing tagout isolation boundaries. This non-repetitive, licensee-identified and corrected tagout violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NHQ Enforcement Poliev.. (NCV 50-336/98-207-04)
M1.3 Soill Durina Fill of Low Pressure Safety Iniection Pioina a.
Inspection Scope (71707)
. The inspector reviewed the March 29,1998, event in which one gallon of radioactive water spilled from a low pressure safety injection (LPSI) vent valve, 2-SI-726, that was -
inadvertently left open during the fill of the LPSI discharge piping.-
b.
Observations and Findinas -
Following the completion of maintenance activities, operators were tasked with filling and venting the LPSI discharge piping using procedure OP 2353A " Filling and Venting Various Safety Related Piping and Components." Procedure OP 2353A, Step 5.6.3, specifies aligning the applicable valves as specified in valve lineups OPS Form 2604L-2,"LPSI System Valve Alignment, Facility 1," and OPS Form 2604M-2, "LPSI System Valve Alignment, Facility 2." Because only the LPSI discharge piping was being filled, a number.
of valves on the valve lineups were N/A'ed. After a pre-job brief, a plant equipment operator (PEO) performed the first check of valve positions in accordance with the valve lineups. However, while performing the lineup with OPS Form 2604L-2, the PEO inadvertently missed closing one valve,.2-SI-726, the LPSI header 2B vent valve.
Discussions with operators indicated that the valve may have been missed because the -
- two valves before and after the missed valve were N/A'ed, thereby making this valve easier to overlook.
The first opportunity to catch the missed valve was by a second PEO who performed the
.second check of valve positions. Discussions with operators indicated the second PEO
_ focused on the valves that were checked by the first PEO. Another opportunity to catch the missed valve was by the Unit Supervisor who was directing the filling evolution. The Unit Supervisor did not adequately verify that the valve lineups were completed prior to proceeding with the next step in Procedure OP 2353A.
When the LPSI pump discharge valves were throttled open to fill the discharge header, approximately one' gallon of water spilled from the open vent valve. The amount of the-spill was small because a PEO, who was stationed in the area for the filling evolution, immediately shut the vent valve but was contaminated in the process.
Operations management was responsive in addressing this event. The inspector reviewed the licensee's causal factor evaluation of the event and found it to be of high quality. The
- failure mode was determined to be human error and inadequate self-verification. As corrective actions, the operating crew that performed the evolution reviewed various aspects of this event, identifying where flawed barriers or event precursors existed and I.
b_
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- how they could be overcome in the future. In addition, a required reading briefing was
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f-provided to the Operations Department that provided lessons learned.
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c..-
Conclusions During the LPSI system filling evolution, due to the inadequate performance and review of
!L a valve lineup,'a vent valve was not closed resulting in a one-gallon spill of water that contaminated a PEO. The failure to adequately perform the valve lirieup as specified in procedure OP 2353Ais considered a violation of Technical Specification 6.8.1. This non-i repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. (NCV 50-
. 336/98-207-05)
U2 M8 -
Miscellaneous Maintenance issues M8.1 (Closed) Unresolved item 50-336/97-207-03:Temoorarv Loss of Reactor Buildina Closed Coolina Water
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a.
Inspection Scone (92902)
The inspector reviewed Unresolved item (URI) 50-336/97-207-03which involved a September 2,1997, event in which the reactor building closed cooling water (RBCCW)
i
. system flow was lost. This unresolved item was opened pending issuance of the licensee's final root cause analysis report associated with this event. This inspection involved interviews with licensee personnel, as well as a review of procedures associated with maintenance activities.
b'
Observations and Findinas
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I Prior to this event, the "C" RBCCW pump, the "C" RBCCW heat exchanger, and the
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Facility 2 RBCCW header were in service cooling Unit 2 plant loads, most notably the spent fuel pool (SFP) Maintenance workers had recently replaced the solenoid on the actuator for valve 2-RB-4.1E, the "C" RBCCW heat exchanger outlet valve to the Facility 1 RBCCW header, but the actuator had not been tested with the replacement solenoid installed. The Facility 1 RBCCW header had been drained to support maintenance and was i
i t filled and vented using Section 5.14 of procedure OP2330A,"RBCCW System." Valve 2-RB-4.1E was an isolation boundary between the operating Facility 2 RBCCW header and the idle Facility 1 header. Using Section 5.7.2 of procedure OP2330A, operations
personnel verified the control switch was in the "close" position before restoring valve 2-
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RB-4.1E to remote operation, but the valve opened when power was restored because the solenoid leads had been miswired. The opening of the valve resulted in the diversion to
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. the Facility 1 header of some Facility 2 RBCCW header flow, which filled remaining voids in the Facility 1 RBCCW header and began filling the surge tank through the Facility 1 header surge line.- This resulted in reduced Facility 2 RBCCW header pressure and loss of the "C" RBCCW pump on a protective low suction pressure trip. To restore the plant, operators entered abnormal operating procedure (AOP) 2564, " Loss of RBCCW," manually j
closed 2-RB-4.1E, and restarted the "C" RBCCW pump. The loss of Facility 2 RBCCW
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flow for approximately 35 minutes resulted in a spent fuel pool temperature increase of less than 1 * F. The licensee documented the event in condition report (CR) M2-971871.
The circumstances that led to the miswiring began in June 1996, when automated work order (AWO) M2-97-0207 was approved to replace the air-operated pilot solenoid on valve 2-RB-4.1E. Because the existing solenoid was being replaced with a different model solenold, the licensee developed replacement item evaluation (RIE) 96-0109, which found the replacement solenoid acceptable. When removing the old solenoid, the maintenance workers documented lifting the solenoid leads using Attachment 3, " Lifted Lead and Jumper Device Data Sheet," of procedure WC10, " Jumper, Lifted Lead and Bypass Control." This involves placing a matching label or marking on each lead as they are disconnected to allow for proper reconnection. Each lifted lead is recorded in the Attachment 3 data sheet which has a signature block for the person installing the label and another signature block for the person who independently verifies the lead markings. The matching labels remain in place while components are being repaired but when components such as this solenoid is being replaced, the labels or markings on the old component leads must be transferred to the new component. After removing the solenoid, the maintenance worker brought the existing solenoid to the maintenance shop and incorrectly transferred the lead markings from the existing to the replacement solenoid,
,
which resulted in the miswiring when the new solenoid was installed. Neither procedure WC10 nor the AWO specifically addresses how to transfer lead markings to a replacement component and therefore, there was no guidance to address how the Attachment 3 data sheet should be annotated or whether an independent verification of the transferred markings was required in this case, the maintenance worker did not reflect the transfer of lead markings in Attachment 3 and an independent verification was not performed.
The scope of the licensee's primary root cause investigation was limited to determining the causes for reversing the solenoid leads. The investigation determined that the applicability of procedure WC10 for temporary or permanent modifications was not well understood by i
maintenance personnel and that insufficient detail was provided in the work control program to control equipment configuration. The investigation identified that the following individual performance factors contributed to the event: (1) a reliance on valve orientation to identify lead markings for the new solenoid, (2) a failure to review design information within the work package, (3) a failure to request a second verification of the lead markings on the replacement solenoid, and (4) a failure to notify supervision that instructions for Attachment 3 to procedure WC10 did not address new wire markings on the replacement solenoid.
As corrective actions, the licensee trained maintenance department personnel in configuration control and self-checking during replacement of equivalent components and performed a review of events involving inadequate self-checki-hv m*tenance personnel Specific procedural guidance covering replacerr n
alent components was not developed.
The Unit 2 Corrective Action Committee reviewed the (
tay z of ouse investigation and identified that aspects of the event associated with pot nairy, ace testing and system restoration were not adequately addressed, so 4.c wped an addendum to the primary root cause investigation. This addenc w ca n
> sequence of activities
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needed for RBCCW system restoration following replacement of the solenoid had been properly controlled in accordance with existing procedures and processes. Based on this, no corrective actions associated with post-maintenance testing or system restoration were identified.
The inspector reviewed the addendum and was concerned that the licensee did not adequately address the fact that although procedures and processes were followed, they allowed the actuator for valve 2-RB-4.1Eto be returned to service, performing a safety function, before the operability of the actuator was established through post maintenance i
testing. The safety function in this instance was that the actuator for valve 2-RB-4.1E needed to keep the valve closed to maintain operability of the operating Facility 2 RBCCW header. In Appendix D to the Northeast Utilities Quality Assurance Program (NUQAP)
Topical Report, the licensee commits to utilize the guidance of Regulatory Guide (RG) 1.33,
" Quality Assurance Requirements (Operation)," and ANSI N18.7-1976/ANS 3.2,
" Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants," which RG 1.33 endorses. Section 5.2.6, " Equipment Control," of ANSI N18.7 states that, until suitable documentary evidence of tests and inspections is available to show that equipment is in conformance, affected systems shall be considered inoperable and reliance shall not be placed on ruch systems to fulfill their intended safety functions.
The inspector also evaluated whether the RBCCW operating procedure was properly followed during system restoration. The global clearance for the Facility 1 RBCCW system provided isoiation for a number of work activities including the work order to replace the solenoid for valve 2-RB-4.1E (AWO M2-97-0207.) As part of the global clearance, the manual operator for valve 2-RB-4.1E was tagged in the closed position. This allowed the solenoid to be replaced while ensuring that valve 2-RB-4.1E remained closed. Steps 5.14.2 and 5.14.3 cf procedure OP2330A required reviewing the AWOs on the global
.
clearance for draining of the Facility 1 RBCCW header and developing the necessary individual clearances prior to filling and venting the Facility 1 RBCCW header. Because the retest of the solenoid for valve 2-RB-4.1E had not been performed, AWO M2-97-0207 remained open. Operators did not establish an individual clearance for this AWO. The inspector determined that this decision was contrary to procedure OP23303A because an individual clearance was necessary to maintain valve 2-RB-4.1E in manual until operations personnel moved the separation boundary and demonstrated the proper operation of the valve actuator through testing.
The inspector evaluated the safety significance of this event and noted that neither the Millstone Unit 2 Technical Specifications nor the Final Safety Analysis Report (FSAR)
requires continuous operation of the RBCCW system in the existing operating condition of the reactor plant (i.e., reactor defueled with all irradiated fuel in the spent fuel pool).
However, Facility 2 of the RBCCW system was performing its safety function of transferring heat from safety-related components to an ultimate heat sink, and no additional procedural controls were present to preclude these circumstances from developing in other operational conditions that require continuous RBCCW system operation.
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..
19 c.
Conclusions The Unit 2 Corrective Action Committee review correctly identified that the primary root
l cause investigation was too narrow in scope and directed an additional root cause Investigation focused on work control and post-maintenance testing. However, the NRC i
found this supplementary root cause investigation incomplete in that no root cause was identified for a loss of system function resulting from a detectable maintenance error. Step 5.14.3 of procedure OP2330A required establishment of necessary individual clearances
,
for open AWOs originally assigned to the global clearance for draining of the Facility 1 RBCCW header prior to filling and venting of the Facility 1 header. Control of this valve's configuration was necessary because: (1) the valve actuator was the subject of an open AWO originally assigned to the global clearance for draining of the Facility 1 RBCCW header; (2) the valve was performing a safety function; and (3) the valve actuator's remote operation had not been satisfactorily tested following maintenance. Contrary to procedure l
OP2330A, the configuration of valve 2-RB 4.1E was not controlled by an individual clearance on September 2,1997. This is a violation (VIO 50-336/98 207-06)of the requirements of Technical Specification 6.8.1.a to implement written procedures for
,
operation of the RBCCW system. Unresolved item 50-336/97-207-031s closed.
In the violation response, the licensee is asked to address the concern that procedure WC i
10 does not provide instructions on the transfer of lifted lead markings from an original component to a replacement component. This is a concern because this event was caused by the incorrect transfer of lead markings and no independent verification was performed
'
which could have identified the error. ANSI N 18.7-1976, paragraph 5.2.6, states that lifted leads shall be controlled by an approved procedure which shallinclude a requirement for independent verification.
M8.2 (Closed) Unresolved items 50-336:423/98-206-03: Channel Functional Test of i
Radiation Monitors a.
Insoection Scope (92902)
The inspector reviewed Unit 2 Unresolved item (URI) 50-336/98-206-03which involved an NRC concern of whether the surveillance procedures associated with digital liquid and gaseous effluent radiation monitors satisfied the technical specification (TS) definition for a Channel Functional Test. This issue was considered unresolved pending review by an NRC regional specialist inspector of the licensee's position paper that concluded they are in compliance with TS. The inspector also reviewed Unit 3 URI 50-423/98-206-03in which the NRC concluded that the surveillance procedures associated with 13 radiation monitors were inadequate in that the method used to satisfy the TS Channel Functional Test for digital radiation monitors was contrary to the TS definition for an Analog Channel Operational Test. Although Unit 3 actions were complete, this issue was also considered unresolved at Unit 3 to allow NRC review of the Unit 2 position paper to ensure a ennsistent NRC approach.
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b.
Observations and Findinas Unit 3 After raising the concern regarding testing of digital radiation menitors at Unit 2, a site-wide condition report was generated by the licensee. However, Ur;it 3 personnel had already identified this concern and were taking corrective actions. As reported in Unit 3 Licensee Event Report (LER) 50-423/97-62,the surveillance procedures associated with 13 radiation monitors were found to be inadequate in that the method used to satisfy the TS Channel Furictional Test for digital radiation monitors was contrary to the.TS definition for an Analog Channel Operational Test (ACOT). TS definition 1.36 specifies that an
" ANALOG CHANNEL OPERATIONAL TEST shall be the injection of a simulated signal into the channel as close to the sensor as practicable to verify OPERABILITY of alarm, interlock and/or trip functions. The ANALOG CHANNEL OPERATIONAL TEST shall include adjustments, as necessary, of the alarm, interlock and/or Trip Setpoints such that the
. Setpoints are within the required range and accuracy."
LER 50-423/97-62specified that the radiation monitors that are affected are those for when ACOT surveillance has been implemented in a manner where the test does not perform a setpoint verification within a required range and accuracy.. For the affected equipment, the ACOT is implemented by performing a source check, and then increasing the conversion factor until the alarm trips. -The setpoints are therefore not verified within required range and accuracy using a simulated signal.
As a result of this ' condition, the affected radiation monitors were declared inoperable. The radiation monitoring system ACOT procedures have since been revised to utilize a pulse generator. The licensee stated that the revised surveillance tests have been performed satisfactorily and that the affected radiation monitors are now considered operable. The inspector found the licensee's corrective actions for Unit 3 to be acceptable.
Unit 2 At Unit 2, the inspector evaluated whether the surveillance procedures associated with digital liquid and gaseous effluent radiation monitors satisfied the Technical Specification 1.11 definition for a Channel Functional Test. Technical Specification 1.11 states that "a CHANNEL FUNCTIONAL TEST shall be the injection of a simulated signalinto the channel
- as close to the primary sensor as practicable to verify operability including alarm and/or trip l
functions." The inspector reviewed the following surveillance:
o Procedure SP 2404AAi" Aerated Liquid Radwaste Process Radiation Monitor RM
- 9116 Functional Test,"
-e Procedure SP 2404AC, " Clean Liquid Radweste Process Radiation Monitor RM-9049 Functional Test,"
l e
Procedure SP 2404AP, " Waste Neutralization Sump Radiation Monitor j
(2CNDRlY245) Functional Test," and;
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i
' 21
e Procedure SP 2404AR," Unit 2 Stack Geseous High Range Radiation Monitor, RM-
!
8168, Functional Test."
- Prior to 1996, the above surveillance procedures clearly satisfied the TS 1.11 definition in that a pulse generator was used to inject a " simulated signal" in place of the primary detector to increase the indicated radiation level to verify that the alarm and tripping of the effluent trip valve occurs at the required setpoint. However, in 1996 the licensee changed _
procedures SP 2404AA, SP 2404AC, and SP 2404AP to perform the Channel Functional Test using a two step process. In one step, background radiation is used to cause an
alarm and tripping of the effluent trip valve. This is accomplished by lowering the digital
'
setpoint to a value slightly below background.' When the test is complete, the setpoint is
- restored to its original value. The second part of the test involves using a check source to verify that the detector responds to increased radiation and is verified on the radiation monitor count rate display. The licensee also changed procedure SP 2404AR to specify
- setting the Rad Conversion Factor to one (1) via the keyboard which causes the displayed i
,
background radiation to increase above the existing setpoint value which causes an alarm.
The inspector had concerns whether using the check source as the " simulated signal" satisfied the TS 1.11 definition because the' strength of the check source is not sufficient
.
for the radiation monitor to reach its alarm / trip setpoint. This necessitates lowering the
,
radiation monitor setpoint below background, or changing the Rad Conversion Factor, l
rather than increasing the simulated signal frequency to verify the alarm'and trip functions
'i at the established setpoint. After evaluating the inspector's concerns, the licensee prepared a Millstone Unit 2 Position Paper that indicated that they believe they were in compliance and also met the intent of TS definition 1.11. The position paper states that in order to meet verbatim compliance, the Channel Functional Test must include: (1) the injection'of a~ simulated signal into the channel: (2) simulated' signal injection as close to the primary sensor.as practicable; (3) verification of channel operability; (4) verification of channel alarm and/or trip functions; and (5) conduct of the surveillance at the stated frequencies. - The position paper then provides a description of how the surveillance satisfy each of the five conditions.
The NRC reviewed the licensee's position paper and did not agree that their test method satisfied the third item, verification of channel operability. Unit 2 TS 3.3.3.9 [and
'
3.3.3.10] states that the radioactive liquid [and gaseous] effluent monitoring instrumentation channels shown in Table 3.3-12 [and Table 3.3-13] shall be OPERABLE with applicable alarm / trip setpoints set to ensure the limits of Specification 3.11.1.1 [and
' 3.11.2.1) are not exceeded. For the liquid digital radiation monitors, the licensee's method does not test channel operability because the simulated signal is not increased to a setpoint value that was set in accordance with TS 3.3.3.9 prior to each effluent release.
l l.
, For the' gaseous digital radiation monitor, the Rad Conversion Factor is changed to increase j_
the count rate signal but this occurs in the digital portion of the circuit rather than "as -
[.
close to the primary sensor as practicable." As a result, the operability of the liquid and gaseous digital radiation monitors is not fully tested because the ability of the amplifiers I
and/or analog to-digital conversion circuitry to process the count rate signal at the higher pulse frequency is not verified.
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When the TS 1.11 definition was written, all of the radiation monitors in the plant were analog. The digital radiation monitors that are now installed allow entering a precise setpoint while analog radiation monitors use a potentiometer to adjust the setpoint.
Therefore, a pulse generator must be used for analog radiation monitors because using the potentiometer is less precise and the setpoint must be verified to be within the required tolerance. When testing digital radiation monitors, entering a setpoint below background radiation level adequately tests the proper functioning of the digital portion of the circuit and allows returning setpoint precisely to the original value. Although the NRC agrees that the digital technology recreates the possibility for an acceptable alternate test method and has approved TS amendments at other facilities to reflect this, the TS 1.11 definition was written for analog technology with the presumption that the simulated signal would be raised to a setpoint value calculated in accordance with TS. Therefore, NRC approval of a technical specification change allows the NRC to review the technical adequacy of the change particularly regarding testing of the amplifiers and/or analog-to-digital conversion circuitry. A technical specification change would also be necessary to reflect whether the alternate test method should be limited to digital radiation monitors because if the TS definition were applied to digital systems in general, data base manipulation alone may not sufficiently test the input circuitry or the hardware and software as a system.
c.
Conclusions At Unit 2, the failure to test the four digital liquid and gaseous effluent radiation monitors in a manner consistent with the TS 1.11 definidon for a Channel Functional Test is considered a violation. (VIO 50 336/98-207-07) The NRC concluded that Unit 3's test method for performing the channel functional test of the digital radiation monitors also failed to satisfy the corresponding technical specification definition, but they had already identified this concern and had implemented corrective actions. Therefore, at Unit 3, this violation is being treated as a Non Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. (NCV 50-423/98-207-08). Unit 3 Unresolved item 50-423/98-206-03 is closed.
M8.3 (Closed) LER 50-336/97-32: Main Steam Safetv Valves Exceed Allowable Setooint a.
Inspection Scooe (92300)
The inspector reviewed Licensee Event Report (LER) 50-336/97-32 which concerned the fact that on September 22,1997, during performance of main steam safety valve (MSSV)
bench testing by an offsite vendor, two of sixteen valves failed to open within their allowable lift set pressures. The inspector confirmed licensee corrective actions by reviewing documentation of licensee actions and discussions with personnel involved with safety valve testing.
b.
Observations and Findinas in their corrective actions, the inspector noted that the vendor rebuilt and successfully retested the valves in question. In their response to the LER, the licensee noted that setpoint drift is an industry wide problem. In an earlier effort to minimize this problem, Technical Specification Amendment No.195, dated January 18,1996, changed the
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setpoint tolerance from +/- 1 % to +/- 3%. This has helped alleviate but not eliminate the
-
problem of setpoint drift causing out of tolerance setpoints.
T.he LER stated that "An evaluation of the results of the Main Steam Valve Test Relief Velve test results for the design basis Loss of External Load, Closure of Main Steam isolation Valve, and SGTR [ steam generator tube rupturel events was performed.- In each case the peak pressure would remain within the margin assumed in the safety analysis..."-
. The inspector reviewed a licensee safety evaluation performed October 15,1997, "MP2 Evaluation of 1997 Main Steam Safety Valve Simmer Test Results" and noted that, except for two valves, the design basis pressures would not be exceeded.- However, these two-
_
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valves can be exchanged for other valves that are within the design basis and the design basis still remains bounding.
Licensee procedure SP2730B," Main Steam Safety Valve Test," paragraph 4.1, provides instructions for bench testing MSSVs at a contractor facility. The inspector reviewed, in
. part, the contractor procedure " Testing of Spring-Operated Main Steam Safety relief Valves," and noted that it conforms to licensee procedural requirements.
c.
Conclusions i
.
. _The failure of two MSSVs to open within their technical specification allowable lift set
pressure is a violation. _ The licensee has performed adequate corrective actions for this
'
. LER. 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 Poliev. LER 50 336/97-321s closed. (NCV 5G-336/98-207-09)
'
U2.lli Enaineerina
.U2 E8 Miscellaneous Engineering issues
,
E8,1 (Ocen) Follow-uo item 50-336/94-201-90:Emeraency Diesel Generator Fuel Oil
Suoolv Tank Capacity - (Undate) Unit 2 Significant items List No. 42
'a.
Inspection Scone (921Q3)
~ The inspector reviewed the licensee's corrective actions to address Follow-up item 50-336/94-201-90,which concerned the fact that the emergency diesel generators (EDG) fuel oil supply tanks did not have the 7-day capacity specified in the final safety analysis report (FSAR),
b. '
Observations and Findinas
- In 1994, the licensee recalculated the length of time the EDGs would operate follov. ev a loss of coolant accident and a loss of normal power and found that the required volume of 12,000 gallons in the fuel oil supply tank for each EDG would not support EDG operation for 7 days as required by FSAR Section 8.3, " Emergency Generators." To address this
- concern, on September 3,1997, the licensee submitted a proposed revision to the FSAR for NRC review. The NRC found the proposed revision to be acceptable and on January w________-----------___
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_-
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a
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l 23,1998, the NRC issued Amendment No. 212 to allow changing the FSAR. The FSAR-change was found acceptable based on two methods for refilling the fuel oil supply tanks
.
that were described in the licensee's submittal.
L The first method is the normal make-up to the fuel oil supply tanks that is provided by tank
. T-47A, an underground diesel oil storage tank that is non-seismic and nonsafety-related,
,
c The licensee's submittal stated that the requirement of fuel oil (approximately 17,700 gallons) to be stored in tank T-47A will be added to the Technical Requirements Manual l.
- (TRM) and will be verified by a surveillance. in addition, the low level alarm for tank T-47A will be adjusted and an associated alarm response procedure will be provided to ensure that 17,700 gallons is maintained. The inspector found that the approved change has
~ been incorporated into the FSAR but other actions such as changing the TRM, changing the alarm setpoint, and changing procedures have not yet been performed. However, this is acceptable since the FSAR change states that it is only necessary to maintain the required volume in the underground storage tank when the plant is operating in Modes 1
' through 4.
? The second method of refilling the fuel oil storage tank described in the licensee's submittalis that " replenishment of fuel oil could be accomplished via an offsite source."
The NRC had concerns regarding the completeness of this statement. The ability to refill
- the fuel oil storage' tank via an offsite source such as a fuel oil delivery truck is important because the underground diesel oil storage tank is not seismically qualified and therefore, cannot be relied upon. The inspector reviewed Condition Report M2-97-2OO7 which was
. initiated on September 9,1998, (six days following the submittal) that stated that currently there are no provisions to directly fill the fuel oil supply. tanks. The inspector' reviewed this concern further and found that: (a) The fuel oil supply tanks do not have a formally established fill connection to fill the tanks from a delivery truck. The licensee stated that
'
t the most likely fill connection is the fuel oil supply tank vent. Filling via this connection is complicated by the fact that the supply tank vents are located on the roof of the 42 foot high EDG building. In addition, a modification to remove the flame arrestor from the vent
<
would be necessary; (b) Temporary equipment such as pumps and hoses have not been pre-staged for directly filling the fuel oil supply tanks. The power to operate a temporary pump has also not been defined. After the inspector raised the concern, the licensee
. contacted diesel fuel suppliers and found that tanker trucks normally do not have an
~ installed pump but smaller delivery trucks have a pump that would provide sufficient discharge pressure to fill the elevated tanks; and (c) There are no procedures or training provided for directly filling the fuel oil supply tanks.
'
L; Technical Support, who was assigned to address the condition report, wrote that " Actual replenishment by tank truck will be handled via recommendations made by the Site
!
Emergency Response Organization (SERO) personnel. This may include, but is not limited
'to the use of the tanker truck / delivery truck installed pump, use of portable pumping
. equipment, etc. It is felt that since conditions during an accident may change, it is not practical to attempt to document via procedure all the possible conditions that may arise in
- an accident. Therefore, no specific method for fuel oil replenishment will be'
.
. proceduralized. It is noted, however, that special pumping equipment may be required, and
- this will be procured and stored for emergency use only." The procurement and storing of
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special pumping equipment has not been completed and Condition Report M2-97 2OO7 has not been closed.
- Although Condition Report M2-97 2OO7 was written after the September 3,1997, submittal, discussions with the licensee indicate that licensee management discussed the
- issue prior to the submittal and determined that the wording regarding the capability to replenish fuel oil via an offsite source was acceptable. The NRC reviewed the wording and determined that the information provided regarding the ability to replenish the fuel oil via an
offsite source was incomplete. With the fuel oil storage tanks capable of supplying only 3.5 days of EDG operation, the ability to refill the tanks in a timely manner becomes a key element for the NRC to consider in the approval of the FSAR revision. Therefore, the fact that the fill connection had not been formally established, necessary pumps and hoses had not been staged, and procedures and training were not complete, is information that should have been provided to the NRC.
The NRC assumed, based on the licensee's statement in its September 3,1997, submittal,'
that the fuel oil storage tanks could be replenished directly from delivery trucks via offsite sources as noted in the NRC's safety evaluation. If the NRC had been aware that the methods to directly replenish the tanks had not yet been determined by the licensee, the NRC would have requested the licensee to submit additional information to assure that the fuel oil storage tanks could be replenished following a seismic event, assuming failure of the nonseismic underground storage tank.
. c.
Conclusions 10 CFR 50.9 requires that information provided to the Commission be complete and
accurate in all material respects. The failure of the licensee to provide complete information in their September 3,1997, submittal regarding tneir capability to replenish fuel oil via an offsite source is a violation. Unit 2 Significant items List No. 42 remains open pending the licensee's disposition of the technical concerns related to this violation, as well as, completion of the actions needed to fully implement the FSAR change. (VIO 50-336/98-207-10)
E8.2 (Undate) Eels 50-336/96-201-42& 43: Material. Eauioment. and Parts List Proaram (Undate - Unit 2 Significant items List No.18)
a.
Inspection Scooe (93903)
The overall site Material, Equipment, and Parts Lists (MEPL) program was reviewed and is
' discussed in Section U3.M3.1 of this report. Various aspects of the Unit 2 MEPL were
previously reviewed in NRC Inspection Reports 50-336/97-202,203 and 208. Although i
the licensee has not provided an updated Unit 2 Significant items List package for NRC
,
L
. review, this section provides an overview and update on the specific aspects of the MEPL l
program for Unit 2.
i
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b.
Observations and Findinas
- Background For structures, systems, components, and parts that are considered safety-related (SR), the procurement, tracking, storage, installation, and maintenance of replacement parts must be accomplished in accordance with the requirements of 10 CFR 50 Appendix B. A nonsafety related (NSR) item is generally one that does not perform a safety-related
'
. function and whose failure would not prevent the accomplishment of a safety-related function. When Unit 2 was originally designed, the quality classification was initially defined on a system level. If a plant system performed a safety-related function, then all the components and parts could be assigned a SR designation, while components and parts in nonsafety-related systems may be designated as NSR. ' The quality classification may also be defined at the component level. Even though a component is within a safety-related system, if that specific component does not perform a safety-related function, that component may be designated as NSR. Many components have sub-parts that are defined on a Bill of Materials (BOM). The quality classification may also be defined at the para level. Even though a part is contained within a safety-related component, if that specific part does not perform a safety-related function, that part may be designated as NSR.
At Millstone the designation of safety classification is performed through the MEPL Program in accordance with Specification 944. This includes the initial classification and
. changes in classification such as upgrades or downgrades. The licensee may downgrade a -
SR component or part to NSR, if they can justify, in a MEPL evaluation, why that
>
component or part does not perform a safety-related function. Downgrading of
- components or parts allows them to be purchased and installed to commercial grade rather than safety gr,ade' requirements.
I Controlof NSR Parts in SR Systems At Unit 2, there are approximately 11,600 SR components. _ About 4000 of these SR components have a BOM, containing a total of 115,000 parts. Only 13,000 of these
.115,000 parts have a MEPL evaluation, leaving about 102,000 parts in SR components without an evaluation. Currently, if. work is needed on these'pwrts, without MEPL evaluations, procedures require that they either be treated as SR or a MEPL be performed.
However historically, a number of instances exist where parts of this sort were improperly treated as NSR and thus not all of the quality documentation required of a SR item is available to provide the full confidence of component or part functionality and operability.
. These instances are documented in condition reports, non-conformance reports, and the above escalated enforcement items.. The licensee has been working on the Unit 2 MEPL program for the last two years and has performed many evaluations that begin to address this concern. However, despite a number of meetings and discussions between the licensee and the NRC, a well-defined program to address the historical concern of NSR -
parts in SR components has neither been established or implemented.
!
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. _ _ _.
Inadequate Closure of MEPL related NCRs Escalated Enforcement item 50-336:423/96 201-43 concerned the fact that the licensee's procedures did not provide guidance regarding the criteria to be used in evaluating the adequacy of installed NSR materialin safety related applications. This was determined to be a principal factor in MEPL-related NCRs that were closed without adequate written justification. Section U3.M3.1 discusses the site-wide corrective actions associated with the MEPL Program that were taken to address the violation, which includes updates to:
Specification SP-ST-ME-944, Standard Specification; Material, Equipment, and Parts Lists for in-Service Nuclear Generation Facilities (MEPL program); NGP 3.05, Nonconformance Reports; NGP 6.01, Material, Equipment, and Parts Lists for in-Service Nuclear Generation Facilities; NGP 6.05, Processing and Control of Purchased Material, Equipment, Parts, and Services; and NGP 6.10, Use of the PMMS ID System and BOM Database. The inspector found these updates to be acceptable.
Despite the above, as discussed in NRC Inspection Report 50-336/97-208,the inspector noted additional problems in the Fall of 1997 at Unit 2 whereby many NCRs for MEPL
]
upgrades were closed with "use-as-is" resolutions with no or inadequate resolutions. Unit -
'
2 has since issued an Engineering Department Instruction (EDI) for NCR closure and is currently implementing it. NRC review of this area is ongoing.
c.
Conclusion Several previous reports, including the cover letter for NRC Inspection Report 50-336/97-208, highlighted the concern that the licensee has not yet fully developed broader corrective actions to address past instances where NSR components and parts were inappropriately isstalled in SR systems (e.g., for parts that were classified as
" Undetermined" or "NSR" and had no MEPL evaluations). During this inspection period, the NRC found that the licensee has still not approved an acceptable plan to address this concern. Therefore, at the exit meeting held on May 1,1998, the NRC requested and the licensee committed to provide to the NRC by May 15,1998, a letter describing their plan for dispositioning these MEPL concerns, i
E8.3 (Closed) LER 50 336/96-42: Instrument Channels of Containment Air Radiation Monitors Do Not meet Acceotable Isolation Requirements Between QA and Non-QA Components a.
Inspection Scope (92300)
The inspector reviewed Licensee Event Report (LER) 50-336/96-42which concerned the
fact that on December 18,1996, an engineering review discovered that there was
inadequate isolation between non-QA (Non-safety grade) and QA Category 1 (safety grade)
,
j components in the instrument loops of the containment air radiation monitors, RM-8123
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A/B and RM-8262 A/B. The instrument channels contain a non-QA Control Room recorder,
'
a non-QA local indicator and a non-QA local alarm. These non-QA components did not l
have adequate electricalisolation from QA Category 1 components within the channel, as required by IEEE Standard 279-1971, Criteria for Protection Systems for Nuclear Power generating Systems." Therefore, the RM-8123 A/B and RM-8262 A/B instrument loops
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were considered inoperable. The inspector confirmed licensee corrective actions by reviewing documentation of licensee corrective actions and discussions with personnel involved with making appropriate design changes to the system, b.
Observations and Findinos
- As a result of the above event, the licensee implemented the following near term corrective actions:
A temporary modification was implemented to disconnect the non-QA components
from the instrument channels.
An engineering evaluation was performed to determine the permanent corrective
action.
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The Unit 2 Configuration Management Project (CMP) was used to identify similar
electrical isolation problems.
The inspector confirmed that a temporary modification that disconnected the non-QA local i
alarm and non-QA local indicator was performed on January 3,1997, per Design Change Notice (DCN), DM2-01-1498-96,"RM 8123 A/B and RM 8282 A/B Bypass Jumper IB/J)
Support - Supplement." The Control Room alarm and computer data points remained connected.
Procedure WC-10, " Temporary Modifications", specifies that the Plant Operations Review Committee (PORC)is responsible for establishing a removal date for each temporary modification. Special approval is required to extend the removal date beyond six months.
A review of the Control Room temporary modification log indicates that the temporary modifications for radiation monitors RM 8123 and 8282 are scheduled to be removed by
- May 1,1998.
Design Change Request M2-97-033 was written in October 1997, to permanently disconnect the radiation measurement and alarm display, light and horn for the particulate gas monitors located at the local skid monitor, which had already been disabled by the temporary modification noted above. The modification will also install an isolating device to isolate the non-QA Control Room recorder. A review of the current work schedule for Unit 2 shows that this modification is currently being performed.
i Procedure U2 PI 7, " Graded System Review", was established as part of the Unit 2 Configuration Management Project to establish the accuracy of the licensing basis.
Attachment 2 to this procedure includes the Radiation Monitoring System. Discrepancies were identified as unresolved items (URis). The inspector reviewed a sampling of five URis
and noted that issues concerning failure to provide electrical isolation between QA and Non-QA components had been identified.
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Conclusions The licensee has performed adequate corrective action for this LER. The modification performed will correct the QA/non-QA isolation problem for the two radiation monitors i
reported in the LER. The licensee's CMP process was utilized to perform a review to I
ensure that similar electrical problems were found and corrected. This non-repetitive, licensee-identified and corrected design control violation is being treated as a Non-Cited L
Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. LER 50-336/96-042 is closed. (NCV 50-336/98-207-11)
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.E8.4 (Closed) Violation 50-336/97-208-03: Potential Seismic Interaction with Safety Related Eauioment in the Control Room The inspector reviewed corrective actions taken to resolve concerns with potential seismic j
interaction with safety-related equipment in the control room and periodically examined the l
adequacy of temporary equipment storage in the control room. As corrective actions, the
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licensee locked wheels on equipment with the potential to rollinto safety-related equipment and determined by engineering evaluation that other equipment was adequately restrained. These actions were consistent with the specified criteria contained in procedure OA8 " Ownership, Maintenance, and Housekeeping of Site Buildings, Facilities, and Equipment," for restraining temporary equipment. The licensee also briefed operations personnel on maintaining compliance with procedure OA8 for temporary equipment located in the control room. The inspector has found temporary equipment with the potential for scismic interaction to be adequately restrained during periodic inspections. Therefore, the NRC concluded that the licensee's corrective actions have been appropriate and that this violation is closed-E8.5 (Closed) eel 336/96-06-11. eel 336/96-08-06. eel 336/96-08-08 eel 336/96-08-i 10. eel 336/96-09-10 eel 336/96-201-12. eel 336/96-201-29 eel 336/96-201-36: Closure of Various Escalated Enforcement items (Closed - Unit 2 Significant Items List Nos. 22,26,29,32,33,34,35,and 36)
As part of the NRC Restart Assessment Plan, the NRC developed a Significant items List (S!L) for each Millstone unit to identify those issues that must be adequately addressed by the licensee prior to restart. A number of issues on the Millstone Unit 2 SIL referenced issued that were characterized in NRC inspection reports as escalated enforcement items (Eels). At the time the Unit 2 Sll was issued, it was unknown whether the notice of violation to address these Eels would be issued prior to restart of Unit 2. Since the Eels needed to be dispositioned prior to restart, the licensee began implementing corrective actions and creating closure packages to address these items even though the notice of violation had not been issued. For a number of these Eels, the NRC inspected the l:
technical concerns associated with the eel and found the licensee's corrective actions to be acceptable and therefore, closed the associated SIL items on that basis. However, the Eels remained open pending issuance of the notice of 'violatinn. The notice of violation and proposed imposition of civil penalties was issued by the NRC on December 10,1997. For l
the following four Eels that were included in this notice of violation, the NRC had already l
inspected the licensee's completed corrective actions and found them to be acceptable:
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Unit 2 eel #
SIL #
Description Followup IR eel 96-06-11
CONTAINMENT SUMP SCREEN MESH SIZE &
IR 97 203 ECCS PUMP THROTTLE VALVE CLOGGING eel 96-0910
"B" EMERGENCY DIESEL GENERATOR 1R 97-02 &
FAILURE - INADEQUATE CORRECTIVE IR 97-203 ACTIONS eel 96-20129
FAILURE TO IMPLEMENT CORRECTIVE IR 97-02 &
ACTIONS FOR AUDIT ISSUES INVOLVING 1R 97-207 TRENDING AND PRIORITIZATION OF NON-CONFORMANCE REPORTS eel 96-201-36
INADEQUATE CORRECTIVE ACTION 1R 97 202 &
CONCERNING A SElSMIC DESIGN DEFICIENCY IR 97-203
)
OF A VITAL SWITCHGEAR ROOM COOLER
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The inspector reviewed the licensee's response to the notice of violation dated March 2, 1998, and found the response associated with the four items listed above to be consistent with the followup NRC inspection report that reviewed their corrective actions. Therefore, the four Eels listed above are considered closed.
Additionally, there were four other Eels in the following list in which the NRC inspected the completed corrective actions and found them to be acceptable, but a notice of violation was not issued for these items:
Unit 2 eel #
SIL #
Description Followup IR eel 96-201 12
SEPARATION AND SINGLE FAILURE IR 97 203 CONCERNS FOR WIDE RANGE NUCLEAR INSTRUMENTS eel 96-08-06
IMPLEMENTATION OF CORRECTIVE ACTION 1R 97-02 &
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OF CHANGING OPERATING PROCEDURE TO IR 97 203 LOCK OPEN REFUELING POOL DRAIN VALVES, AS SPECIFIED IN THE FSAR, WAS INADEQUATE eel 96-08-08
INADEQUATE CORRECTIVE ACTION IN LER 1R 97-203 l
336/96-24 eel 96-08-10
INADEQUATE CORRECTIVE ACTIONS TO IR 97-02 &
ADDRESS UNIT 1 HEAVY LOADS LIFTED IR 97 203 OVER THE UNIT 2 VITAL SWITCHGEAR ROOM in a letter dated April 16,1998, the NRC indicated that the first item listed above was not a violation and therefore, eel 50-336/96-201-12is considered closed. For the remaining three items, the April 16,1998, letter indicated that the NRC was granting enforcement discretion. Nevertheless, the NRC still expected the licensee to implement corrective action to address these items. The NRC has inspected the corrective actions for these
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items and found them to be acceptable and therefore, eel 50-336/96-08-06, eel 50-
,
336/96-08-08,and eel 50-336/96-08-10are considered closed.
I The SIL items for the eight Eels discussed above have been characterized as " Closed" but had a clarifying note indicating that enforcement action was pending. The clarifying note is no longer'necessary and will be removed during the next SIL update.
i Report Details Symmarv of Unit 3 Status Unit 3 remained in cold shutdown (Mode 5) at the start of this inspection period. On April 7,1998, the operators raised the reactor coolant system (RCS) temperature, using one reactor coolant pump (RCP), to achieve hot shutdown (Mode 4) conditions. On April 8, 1998, the licensee identified that they failed to meet a TS requirement when entering
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Mode 4. With a second RCP in operation, the plant was heated to hot standby (Mode 3)
conditions on April 10,1998. An engineered safety features (ESF) actuation (i.e., the automatic start of the auxiliary feedwater pumps) occurred upon a "lo-lo" level signalin the
"C" steam generator on April 11,1998. After stabilizing the plant conditions, the operators conducted a cooldown back to Mode 4; evaluated the condition of the motor driven feedwater pump, which had been secured causing the ESF actuation; and re-commenced beat-up to Mode 3, all on April 11,1998. Normal operating pressure and temperature was attained in the RCS on April 12,1998.
Unable to complete a required surveillance test on the turbine driven auxiliary feedwater (TDAFW) pump within the allowed outage time of the plant technical specifications (TS),
the operators conducted an RCS cooldown to Mode 4 conditions on April 15,1998. After implementing TDAFW pump and valve work, the unit was returned to Mo'de 3 on April 23, 1998. Upon initiation of required Mode 3 testing of the TDAFW pump / system on April 24, 1998, pump casing / shaft seal steam leaks were identified and subsequent testing resulted in pump turbine trips. With the inability to establish TDAFW pump / system operability in accordance with the TS, the operators conducted another plant cooldown to Mode 4 on April 26,1998. At the end of this inspection period, Unit 3 remained in Mode 4 for the licensee to conduct TDAFW pump seal leakage repairs.
An Operational Safety Team inspection (OSTI) was conducted at Unit 3 from February 16, 1998 through the exit management meeting on May 5,1998, inspectors from the OSTI team were on site during significant portions of time during this current inspection report period, including the plant Mode changes described above. The TS violations, ESF actuation, and other operational control problems identified by the licensee, and further inspected by the OSTI, are assessed and documented in the OSTI report, 50-423/97-83.
In the NRC Notice of Violation (NOV) and Proposed imposition of Civil Penalties issued to Millstone Station on December 10,1997, several escalated enforcement items (Eels)
documented in previous Millstone inspection reports were cited as NOVs, each provided a NOV letter unique identifier. Closure of several of these Eels are discussed in the following sections of this inspection report. While these specific Eels are considered to be technically closed, the associated NOVs, provided with their own five-digit letter unique
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identifier, remain administratively open for further review,'as required, of the licensee response to the violations and the NRC determination if further inspection of the corrective actions is warranted.
U3.1 Operations I
U3 01 Conduct of Operations
01.1 Mode 3 Technical Specification Review a.
Inspection Scope (71707. 92901)
On April 8 the licensee identified that they had not met the requirements for a technical specification (TS) for the reactor coolant pumps upon entry into Mode 4. This was the licensee's first entry into this Mode following the March 1996 shutdown. The inspecto'
reviewed the licensee's corrective actions in response to this event and independently reviewed TS to verify compliance with TS prior to entry into Mode 3 later that week. (The initial TS noncompliance was documented in LER 98-22 which was issued after this inspection period and will be inspected at a later date.)
b.
Observations and Findinos The licensee reviewed TS and identified those TS sections that were required upon entry into Modes 4 and then 3 and confirmed that plant conditions and surveillance data supported both Modes. Where they did not, the licensee verified that the aopticable TS j
- action statements were entered. The inspector reviewed the licensee's TS to identify j
those sections that would become effective upon entry into Mode 3 and confirmed that
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the licensee had also reviewed them and entered the appropriate action statements.
i Compliance with selected TS for emergency core cooling systems, auxiliary feedwater, and boration flowpaths were independently verified through inspector control board walkdowns and review of surveillance data.' The licensee's review encompassed the Mode 3 TS reviewed by the inspector and effectively verified compliance.
Discussions with nuclear oversight personnel confirmed that they had also reviewed TS compliance, using a combination of the licensee's and inspector's methods, following the aforementioned event and found no significant problems. This conclusion was
' documented in the nuclear oversight restart verification plan key issues status for April 17.
c.
Conclusions The licensee's actions following the failure to comply with technical specifications (TS)
upon initial entry into Mode 4 were appropriately scoped and performed. They ensured current compliance with Mode 4 TS and reviewed those TS which would be applicable in Mode 3. Through independent control board walkdowns and surveillance reviews, the inspector independently verified licensee compliance with selected Mode 3 TS. Associated discussions of this area can be found in NRC Inspection Report 50-423/97-83.
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U3 03 Operations Procedures and Documentation l
03.1 Procedure Uoarade Proaram Proaress (Update - SIL ltem 80)
a.
Insoection Scope (92901)
The purpose of this inspection was to determine the status of the Unit 3 procedure upgrade program (PUP) as it nears completion. Previous inspections were performed in this i
area and the findings were documented in NRC Inspection Reports (IR) 50-423/97-01 and 97-203. Discussions were held with licensee personnel and various documents reviewed to determine the status of Millstone Unit 3 procedures.
b.
Observations and Findinas The Unit 3 PUP is essentially complete. Only two procedures remain to be upgraded - (1)
OP 3341C, " Carbon Dioxide Fire Protection System" and (2) OP 3336D," Condensate Demineralized Liquid Waste System." The licensee stated that these procedures would not be upgraded until just prior to Mode 2. Both procedures were considered by the licensee to be technically adequate and only needed format changes to conform to the document control (DC) administrative procedures.
Performance indicators in the Fall of 1997 indicated the that licensee considered both procedure implementation and technical adequacy to be less than satisfactory. Recent performance indicators by both the line organization and the Nuclear Oversight organization, showed that there is currently satisfactory performance in the procedures area. The inspector confirmed these conclusions by reviewing recent Oversight performance indicators, an oversight evaluation report, a management oversight and effectiveness report and information provided in an NRC briefing book.
There is evidence through the CR process that both the line organization and Nuclear Oversight have been identifying procedure problems and that corrective actions or procedure changes are being made. in addition, procedure DC-4, " Procedure implementation" was extensively revised in October,1997. Extensive training was performed after this revision had been issued. This appears to have caused a reduction in procedure violations.
There was a recent CR identified at Unit 1 in which changes to valve lineup procedures had not been implemented in the plant. Hence, a number of Unit 1 valves were determined not to have been in the correct position. The inspector performed a review to determine if valves are properly positioned if procedures or system lineups are changed. The inspector verified, that for Unit 3, a feedback memorandum is issued when changes are made to
. system valve lineups. The object of this memorandum is for operators to verify that the appropriate valves were repositioned as a result of the change. This system minimizes the chances that valves would remain in an incorrect position following a change to a procedure or valve lineup. A sampling of recent feedback memoranda were reviewed by the inspector.
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As part of the ICAVP process, NRC Inspections 50-423/97-206and 209 have been completed. These inspections reviewed a total of 64 licensee technical procedures. Only six minor instances of technical procedure inadequacies were identified. The results of
~ these inspections indicate that licensee procedures appear to be adequate. NRC Inspection
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97-83 (OSTI) is currently in progress. This inspection will extensively review both procedure adequacy and implementation. In addition, the ICAVP process is currently
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.' performing corrective action inspections.
c.-
Conclusions Although two procedures remain to be upgraded, the PUP is effectively completed.
j Licensee indicators and recent NRC inspections indicate significant progress in the procedures area. SIL ltem 80 is hereby updated, but remains open pending completion of
'the NRC OSTI and ICAVP inspections and evaluation of their results.
-l 03.2 (Undated) Unresolved item URI 423/96-01-07: Safety Grade Cold Shutdown Eauioment Controls (Update - SIL ltem 14)
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a.
Insoection Scone (92901)
in the initial inspection, the functions of systems and equipment required for safety grade q
cold shutdown (SGCS) were reviewed, and the team observed that there were inadequate
l administrative controls on some of this equipment governing its removal from service and
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its periodic surveillance.L Specifically, the inspector observed that two of the four safety-related main steam atmospheric relief bypass valves (MSARBVs) (3 MSS *MOV74A and B)
i had been removed from service for maintenance during plant operation, along with their corresponding block valves (3 MSS *MOV18A'and B), by de-energizing the block valves in the~ closed position. This had adversely affected the ability to perform SGCS, and at that time, no Technical Specification or other administrative controls were in place for these valves. The inspector also_ observed that there were inadequate controls for equipment required to support other design basis events, such as Appendix R fire shutdown and j
station blackout.
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In response, the licensee initiated adverse condition report ACR 7745 to address administrative controls (1) for these specific valves and (2) for the other design-basis
contingent" equipment. The inspector also noted that FSAR Section 5.4.7.2.3.5 l
erroneously implied that achievement of RHR initiation, rather than cold-shutdown was the
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required SGCS endpoint.
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A subsequent inspection observed that these same valves were also required to respond to l
a steam generator tube rupture (SGTR) design basis accident, as described in FSAR Section j
J15.6.3, and that their previously observed removal from service during plant operation had j-constituted a reportable condition per 10CFR50.73(a)(2)(ii)(B).
Resolution of this URI required verification that (1) a 10CFR50.73 report had been made
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' for the above described removal from service of the steam generator atmospheric relief bypass lines, (2) that FSAR Section 5.4.7.2.3.5 had been clarified regarding the SGCS i
endpoint, and (3) that the requisite administrative controls for the SGCS equipment and L
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other " design-b' asis" equipment, including Chapter 15 accident related equipment, had-been established.
b.
.Qhservations and Findinos 10CFR50.73 Report:
' On April 17,1997, the' licensee submitted LER 97-029 to the NRC in accordance with L
10CFR50.73 to report that, between February 8,1996 and March 18,1996, two of the
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l four MSARBVS,3 MSS *MOV74A&B,were removed from service by de-energizing closed the upstream block valves,3 MSS *MOV18A& Respectively, thereby incapacitating equipment essential to assure satisfaction of the design basis requirements relating to the SGTR accident and other design basis events. The cause was identified as failure to recognize design and single failure requirements necessitating operability of the MSARBVs, and failure to recognize the need to provide the necessary administrative controls. The
- corrective action was to change Technical Specification 3/4.7.1.6," Steam Generator Atmospheric Relief Bypass Lines" to establish these controls, which was instituted under License Amendment No.151 dated 10/2/97. Therefore, the 10CFR50.73 reporting element of the URI verification was closed. However, a' wording concern still remained with the Technical Specification change as described below under Administrative Controls.
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FSAR Clarification:
i l-The inspector observed that FSAR Section 5.4.7.2.3.5 was changed by FSAR change l.
request 97198, dated 6/97, to identify that the licensing basis shutdown for SGCS was,
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indeed, cold shutdown and by FSAR change request 97-108 dated 9/97 to insert a
. paragraph containing a phrase that the licensing basis time limit for this shutdown was 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br />. : Therefore, this ' element of the URI verification was closed.
Administrative Controls:
.The licensee's initial response to this finding was to draft a new Technical Requirements Manual (TRM) section entitled " Equipment Required for Safety Grade Cold Shutdown" which provided administrative controls for the MSARBVs and their respective block valves, as well as the other safety-grarie equipment required for SGCS. However, upon realization that these valves were also required to support the SGTR design basis accident, as described above, and the discovery that they had been removed from service for more than one month during plant operation in 1996, the licensee made a 10CFR50.73 report to the NRC and instituted the above described Technical Specification to administratively control them rather than the TRM as originally intended.
The inspector reviewed the new Technical Specifications and their Bases and identified a
, wording weakness that created the potential for misinterpretation. Technical Specification 3.7.1.6 stated,1"Each steam generator atmospheric relief bypass valve (SGARBV)line shall be OPERABLE, with the associated main steam atmospheric relief isolation (block) valve in the open position." The inspector was concerned that this wording criuld be interpreted to mean that it would be acceptable for the block valve to be inoperable, i.e., not fully
)
operable mechanically, electrically, and otherwise, as long as it was open. However, this
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would not be acceptable, since operability of these valves was required to assure the capability to isolate a failure of a main steam dump valve or SGARBV to close. Without this capability, in a SGTR accident, such a failure on the f aulted steam generator would prevent the accident recovery as described in the FSAR. The wording of the Bases was also ambiguous as reflected in the following statement, "Because of the electrical power i
relationship between the SGARBV and the block valves, if a block valve is mainta'ined closed, the SGARBV flow path is' inoperable because of single failure consideration." This
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seemed to imply that if the block valves were open, regardless of their operability, single
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failure concerns were eliminated, which was not correct.
Tha licensee agreed to review the question of TS operability with the block valve open, but incapable of c!osing. The licensee's initial position was that such a condition would constitute SGARBV "inoperability". The inspector agreed with this position and requested the licensee to document this position, which will be reviewed during a subsequent inspection of this SIL item.
The inspector also identified another apparent weakness in the Technical Specification. If an LCO were declared on an atmospheric relief line with the block valve closed, and a SGTR accident were to occur on that steam generator, its pressure would increase to the safety valve setpoint where it vuould remain until the RCS-to-steam-generator pressure was equalized by the operators' responses. Further RCS cooldown and depressurization in order to get to RHR initiation would allow the safety valve to reseat. However, from that point onward, the operators would have no direct control over the faulted steam generator's pressure. As RCS pressure decreased, flow through the broken steam generator tube would reverse, going from the steam generator to the RCS. This would have two negative effects; first, dilution of the RCS boron, and second, potential disruption of natural circulation in the RCS, neither of which had been analyzed. Additionally, no operating procedures addressed this condition.
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This finding also led the inspector to identify a single failure design concern for these valves; for a SGTR, this inability to control steam generator pressure after RCS-to-steam-generator pressure-equalization would also exist for a single failure to open of the SGARBV on the faulted steam generator.
In response, the licensee initiated CR M3-98-1419, dated 3/13/98. The inspector reviewed this CR and found it inadequate in two regards: (1) It addressed only the above described single failure concern, but not the LCO concem, and (2) it indicated that this concern only applied to the valves on steam generator "C", since a steam release pathway
' was available for the other steam generators by operating the AFW steam driven pump, which could not be supplied from the "C" steam generator. However, since no analyses existed showing that the plant could be brought to RHR initiation conditions within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, as required by FSAR Section 15.6.3.2, using this pathway, this assessment by the licensee had no analytical basis. Additionally, no operating procedures addressed this cooldown Mode, although the licensee did indicate that emergency operating procedures did specify operator actions in response to the postulated failures during accident conditions.
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The licensee also initiated's deportability determination which concluded that this discovery i
was not reportable per 10CFR50.72,10CFR50.73,or 10CFR50.9(b). This conclusion was based upon several positions that were questioried by the inspector, as follows-For failure of the MSARBV to open on the faulted steam generator, the deportability
g determination took credit for several operator actions at the valves, such as i
manually opening the valve, rigging a temporary air supply to the corresponding
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main steam dump valve to open it, or manually opening one of the main steam j
safety valves.
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l Although the main steam dump valves; which the licensee took credit for in this
' ovaluation, were qualified to perform a closing safety function, they were not i
qualified to perform an opening safety function.
l No procedures were in place to perform the operator actions taken credit for, and
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no analyses were in place showing that the actions could be performed in the time frame committed to in FSAR Section 15.6.3.2.
The evaluation only addressed a disk-to-stem-separation mechanical failure and
concluded it was not credible. Based on this, it concluded that mechanical f ailure was not credible, and that for en electrical failure, the valve could be operated by the hand wheel.
I Control of the balance of the safety-grade equipment required for SGCS was included in 3TRM-7.6, Rev 1, dated 11/26/97, which the inspector reviewed. <This document appeared to be adequate to provide the necessary control; however, the inspector
' considered one of the procedure definitions to be misleading. The procedure defined
" Reasonable Period" to achieve cold sh' tdown by stating that the Standard Review Plan u
clarified reasonable period to achieve RHR entry conditions as 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, and that the time from RHR initiation to cold shutdown was "D91 specified", with no additional definition. As presented, this could mislead a reader that the required time to SGCS was undefined. To l -
the contrary, as described above, FSAR Section 5.4.7.2.3.5 stated the licensing basis time i
limit as 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br />. The licensee agreed with this observation and initiated a TRM change to revise this definition.
In reviewing this item, the inspector reviewed FSAR Section 15.6.3.2, which stated, "The j
steam generators are controlled at the safety valve setting rather than at the atmospheric
. dump valve setting." This statement was incorrect; none of the steam generators are L
controlled at the safety valve setting for the SGTR accident, since their pressure cannot be regulated,' which is required for recovery from this accident. Fw this event, operators may control the steam generator practure with tha atmospheric dump valves, or if they are
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- unavailable, with the safety-related SGARBVs. Although this error did not appear to have
- been previously recognized, it was already being corrected as a part of a large FSAR revision in process at the time that removed this statement as a part of a complete rewording of this sectio ?
c. Conclusions Technical Specification 3/4.7.1.6 had been iristituted to provide the necessary control for the MSARBVs and their associated block valves. However, its wording and its Bases'
wording was ambiguous with regard to whether it was necessary for the MSARBVs block valves to be OPERABLE as well as OPEN in order for the bypass lines to be considered OPERABLE. The licensee intends to provide follow-up documentation to address this concern.
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The FSAR had been updated to clarify the end point for the SGCS event. Administrative controls had been instituted to control the operability and surveillance of equipment.
important to SGCS and other safety significant events. However, one of these controlling
_ documentsi 3TRM-7.6, contained a misleading statement regarding the time from RHR g
q initiation to cold shutdown. - This is being corrected by the licensee.
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Additionally, for a SGTR accident with the single failure of the MSARBV to open on demand on the faulted steam generator, then the licensing basis ability to safely bring the plant to RHR initiation conditions as described in the FSAR, in the 8-hour time frame described in the FSAR, may not be achievable. in the same vein, for an LCO allowed by
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Technical Specification 3/4.7.1.6 on a SGARBV line, if a SGTR occurs on that steam generator, the effect is the same as the single failure described above. Therefore, it may I
not be possible to safely bring the plant to RHR initiation conditions as described in the
- FSAR, in the 8-hour time frame described in the FSAR.
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-_ Therefore, this unresolved item URI 96-01-07 remains open to track resolution of the effect of block valve operability on _TS compliance, as well as the issues involving procedural adequacy and operator response to the SGTR accident conditions described above. SIL ltem 14 is hereby updated.
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03.3 (Closed) Irispector Follow item IFl 423/97-02-16: Steam Generator Tube Ruoture f
(SGTR) Analysis
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a. Insoection Scope (9290D A previous inspection addressed the SGTR event and reviewed one of the applicable i-Westinghouse analyses, WCAP-13OO2," Margin to Overfill Analysis for a SGTR for
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Millstone Unit 3 Four Loop Operation". This analysis was based on methodology in WCAP-
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- 10698, which was' performed on a reference 3-loop plant. The reference plant required
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l only one _MSARBV for RCS cooldown in order to equalize RCS pressure with the faulted l
steam generator to terminate the break flowi whereas Millstone 3 required two.. The worst l-case single failure for the reference plant had been loss of one MSARBV, which decreased
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the steam dump capacity from the unfaulted steam generators by'50E The in'spector questioned whether a more limiting single failure for Millstone 3 might be loss of an emergency diesel generator (EDG), which would cause loss of two MSARBVs (a 67%
cooldown capacity loss), leaving only one to provide RCS cooldown. WCAP-13OO2 had not addressed this scenario.
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b. Observations and Findinas in response to this question, the licensee requested Westinghouse to perform an additional SGTR margin-to-steam-generator-overfill analysis case addressing loss of an EDG. As a part of this reanalysis, Westinghouse revisited the base case for single failure of one MSARBV, incorporating Model refinements identified since the original analysis was performed. This reanalysis (Westinghouse' report letter NEU-98-OOS, dated 1/15/98)
determined that,' for the new base case, the margin to steam generator overfill was 408 cubic feet, versus 225 cubic feet for the original base case. For the loss-of-EDG scenario, the margin was increased to 615 cubic feet, a 51 % improvement over the new base case.
This was caused by the fact that the loss of the second MSARBV and its RCS cooldown capacity as a result of the EDG failure was more than offset by the loss of the associated ECCS train, which significantly reduced the RCS injection flow and the resultant tendency _
- to maintain RCS pressure.
Tha inspector reviewed the reanalysis report and found no significant discrepancies.
However, one minor discrepancy was identified. One of the refinements since the original analysis was in the modeling of the MSARBV set pressure. The original analysis modeled the nominal 1140 psia set pressure by allowing the valve to start opening below the nominal value and having the valve full open at the set pressure. The report stated that the improved model assumed the valve started to open at 1.5% below the nominal value, with full open at 1.5% above the nominal value. Since the RCS-to-steam generator equalization pressure was slightly increased by this change, the margin to overfill was slightly improved. Conversation with the cognizant on-site Westinghouse engineer revealed that, per a separate sensitivity study, a 3 cubic feet increase in the overfill margin had resulted from this changed assumption. However, no basis was provided for the 3%
relief pressure accumulation implied in the assumption change.
Westinghouse's review of.this question determine'd that the new assumption, as stated, was incorrect. Rather than having the MSARBV starting to open at 1.5% below the nominal set pressure, as stated, the analysis had actually used the nominal set pressure as the opening point, with the valve full open at 3% accumulation. However, the model utilized the actual accumulation that would be experienced, dependant on the required modeled flow rate. The basis for using the nominal set pressure as the opening point rather than the low end of the setpoint tolerance band was that this was standard L
methodology that had been accepted by the NRC, and its effects were minimal compared l
with other parameters where the conservative limits of the tolerance bands were used.
L The Westinghouse engineer committed to revise the report to accurately reflect this assumption and its basis.
The inspector also questioned one of the basic unstated assumptions inherent in this analysis, that a diesel generator failure was the most limiting single failure. Review of the one-line electrical drawings indicated that a breaker or bus failure feeding either pair of MSARBVs could leave all of the ECCS pumps in that division and much of the 480 volt ECCS equipment still in operation. Therefore, the potential existed that division of ECCS could still be supplying the RCS, which was contrary to a basic assumption in the analysis.
Therefore,it appeared that this analysis did not adequately address the original concern, L
that there may be more limiting failures than the single failure of a MSARBV.
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c. Conclusions -
1 The inspector conclu'ded that WCAP-1302 was correct except for the minor discrepancy in one of the analysis report's assumption descriptions, as described above, and that it did l
/ demonstrate that failure of a diesel generator was enveloped by the original SGTR analysis that assumed failure of a MSARBV as the most limiting single failure. Therefore,IFl
,423/97-02-16is closed. However, it was also concluded that the assumption of a diesel
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generator failure may not have been the most limiting electrical failure for this event, i.e., a failure of electrical equipment supplying either pair of MSARBVs that would leave ECCS equipment on that division still operating could constitute a more limiting failure not enveloped by the current analysis for this event. Therefore, unresolved item URI 423/98-207-12is opened to track resolution of this concern.
- U3 07 ' Quality Assurance in Operations 07.11. NUREG 0737 Item No. II.E.4.2 Containment isolation Dependability (92901)
(Update - SIL ltem 38)
This item addresses several aspects of containment isolation that are descobed in seven sub-items, related clarifications and an Attachment. These were initially reviewed and accepted in the SER, Section 6.2.4, SSER 2, Section 6.2.4, and inspection report 423/86-08. Items 1,4,5,6, and 7 were reviewed and found acceptable in IR 423/98-206.
Items 2 and 3 call for the definition and specification of non-essential (NE) systems and the automatic isolation of these systems or that they be sealed closed. FSAR Section 6.2.4.1.1 and Table 6.2-65 defines and lists the essential and NE systems and containment isolation valves (CIVs). The FSAR states that all NE valves which may be open during normal ogieration are automatically isolated, while the remainirig NE lines are isolated with manual valves locked closed during normal operation. The inspector reviewed the lists and selected NE CIVs without automatic signals for verification that administrative controls exist for sealing the valves closed. The licensee presented procedure OP 3260B, Equipment Control and OPS Form 32608-1, Locked Component
' Checklist, that established the controls to ensure that required valves are properly locked / sealed in position. All selected valves were contained in the Checklist with two exceptions. For penetrations 1 - 4 for the Main Steam lines, valves 3 MSS *PV20A-D and valves 3 MSS *MOV74A & B are listed as NE, normally shut (and shut for accident conditions), and do not automatically isolate, but they are not on the locked valve checklist. The NRC SRP has different criteria for Essential and NE valves. The licensee investigated and identified FSARCR 97-MP3-530 which had been approved 12/5/97 but not yet entered in the FSARs. This changes the penetrations to Essential. The inspector
. questioned the implications of this reclassification in light of the SRP 6.4.2 criteria about provisions for leakage detection for essential penetrations. The NRC Project Manager and the Containment Systems Branch of NRR investigated this issue and determined that these penetrations should be essential and that no additional actions related to leakage are required. Remaining on this item is an update of the FSAR in this area.
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In summary for ll.E.4.2, the licensee has acceptably addressed all of the seven subitems, except the FSAR update.
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07.2 Commitment Trackina and Validation on CP/NOV Corrective Actions (40500)
.The NRC issued a Notice of Violation and Proposed imposition of Civil Penalties by letter dated 12/10/97. The licensee responded to this in a letter (B16996) dated 3/2/98. The inspector began a review of the identified corrective actions and commitments from the letter and noted that problems were identified in the small sample reviewed, as follows:
, For_the NOV (letter unique identifier 04033),'which addressed RPCCW system temperatures, two corrective actions were noted in the NOV/CP letter as complete,
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1. OP 3208 " Plant Cooldown," was revised to provide specific direction to prompt operators to initiate a CR and notify the system engineer when exceeding temperature limits.
2. A computer priority alarm was instituted to alert the operator of a high temperature
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condition which prompts the operator to initiate a CR and notify the system engineer.
When the inspector attempted to verify these two items during this inspection, it was discovered that neither corrective action was currently in place.
Also, for NOV (letter unique identifier 04043), the inspector noted that not all of the procedure changes described in the NOV/CP response letter had been source-noted with a
" cloverleaf" to indicate that it related to a docketed commitment that had to be maintained.
Licensee Controls on NRC Commitments and Correspondence 10 CFR 50.9(a) requires informatio'n provided by a licensee to the Commission be complete and accurate in all material aspects.-
- The licensee has established controls for NRC commitments in procedures,- RAC 06, "
j Regulatory Commitment Management Program," Rev. O, effective 12/18/97, and RAC 08,
Regulatory Communications and Docketed Correspondence, Rev. O, effective.12/18/97.
RAC 06 addresses controls for docketed commitments, including the following elements:
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" define, disposition, implement and track, maintain, link, change, report, and monitor."
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RAC 08 provides management controls for regulatory activities, primarily docketed
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correspondence. RAC 08 requires validation of outgoing cornmitments and statements of
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fact.
RAC 8, note page 8, states that validation is required for material statements of fact used in all docketed correspondence. Step 1.4.15 states that if validation is required refer to Attachment 4 for guidance. Attachment 4 states that tho' validation process requires that each completed corrective action and each statement of fact be validated (i.e., supported by a document that serves as the basis). The lead Functional Manager is responsible for ensuring the information is complete and accurate in accordance with 10CFR50.9(a).
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RAC 6, Step 1.7 states that regulatory commitments must be explicitly linked to applicable
- hardware, programs, or procedures that implement or satisfy the regulatory commitment.
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Step 1.7.1.a states, ".. Verify ' cloverleaf' is entered at the appropriate step (s) in the procedure with a reference to the regulatory commitment."
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Licensee resoonse The licensee issued CR M3-98-1973 on 4/15/98 and determined that OP 3208 had been changed on 3/4/98, two days after the NOV response letter, to remove the committed
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change. Further, the new alarm (from the commitment) was found to have been removed on 11/4/97, three months before the NOV response letter was issued. The licensee changed the computer alarm to a control board annunciator and developed an Alarm Response Procedure with a step to write a CR.
Discussions with the licensee on 4/21/98 and a review of the licensee's computerized commitment tracking system showed the most (if not all) of the commitments in the database from the NOV response letter were statused as "open" indicating that they have only been entered into the database 'and that no work has been done to validate or assign required actions on the items. The licensee acknowledged that the actions on these items were behind schedule.
' Discussions with licensing personnel also revealed that the source noting in accordance with RAC 06 is often delayed after a commitment letter is sent to NRC (delays can be up to 6 months), and that little action has been taken to address source noting of the many commitments in this NOV/CP letter.
The inspector noted that this area of commitment tracking, validation, and source-noting merits further attention by the licensee. Therefore, this issue remains unresolved (URI
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423/98 207-13)pending further review and the appropriate actions by the licensee.
U3 08 Miscellaneous Operations issues (92700)
08.1 (Closed) LER 96-037-00: Soent Fuel Pool Coolina System Potentially Inocerable Followina an SSE Due to Failure of a non Seismic Connectina Pios (Partial-SIL ltem 70)
. a. insoection Scope (92700)
This item was previously reviewed in inspection report 423/97-207. A licensee engineering review determined that a failure of the non-seismic purification lines connected to the Spent Fuel Pool (SFP) could drain the SFP to the point where a loss of SFP cooling occurred. The purification lines are connected to the SFP at the same elevation as the SFP cooling system suction lines. The drain down of the SFP to the level of the purification line penetrations would result in the SFP cooling line being partially out of the water. In the
' drained-down condition, SFP cooling would be unavailable until repairs to (or isolation of)
the purification lines could be accomplished and makeup provided to restore SFP level.
Having a non-seismic purification line at the same level as the SFP cooling line was caused by an oversight in the original design of the plant. The discovery of this flow path out of the Spent Fuel Pool led to another engineering review to determine if there were other similar flow paths out of the Spent Fuel Pool.
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b. Observation and Findinas~
.The inspector reviewed LER 96-037-00, SIL 70, and ACR M3-96-0898 along with other associated documentation and engineering drawings. This item had been previously reviewed and left open pending completion of piping changes to the SFP.
After the modifications were completed, the SFP water level was lowered to the lowest level thought credible for a test of the SFP cooling system. At the lowest water level the two fuel pool cooling pumps were observed to create a vortex at the pump intake. As a
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result of work accomplished by an outside laboratory and discussion's with the pump I
manufacturer, the licensee decided that the vortex at the pump inlet would entrain too much air resulting in eventual damage to the pump. The vortex is to be eliminated by adding a design change to put a finned or vaned flow-straightening device at the pump inlet. This anti-vortex device is currently being designed and the licensee has indicated that
' it will be installed and tested prior to Mode 2.
c. Conclusions The completed corrective actions taken by the licensee are deemed adequate.
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LER 96-037-00is closed.
08.2 (Closed) Licensee Event Report 97-019-00 Follow-uo: Violation of Technical Specification as a Result of Failure to Account for Instrument Uncertainty in DWST Level (Closed - SIL ltem 70) -
a. Insoection Scope (97200)
Licensee Event Report (LER) 97-019-00, dated 3/20/97," Violation of Technical Specification as a Result of Failure to Account for Instrument Uncertainty in DWST Level",
j reported that on February 18,1997, with the plant in Mode 5, it was discovered that Technical Specification Limiting Condition for Operation (LCO) 3.7.1.3 for the.
demineralized water storage tank (DWST) had not been met on some historical occasions.
Specifically,'as a result of not allowing for instrument uncertainty in the corresponding-surveillance procedure, the requirement that the contained volume of the tank be at least
- 334,000 gallons of water had not been met. This volume was required to meet the design basis, which was' sufficient water to maintain the RCS at hot standby for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> while discharging steam to the atmosphere, concurrent with a loss-of-offsite-power (LOP), and with a subsequent 6-hour RCS cooldown to 350'F. The cause was identified as failure to adequately define the term " contained volume" within the Technical Specification LCO requirements or bases sections. The LER's corrective action wcs to make provisions in the surveillance requirements by 10/10/97 to assure adequate volume was contained in the DWST. This target date was subsequently changed, by a licensee letter to the NRC, B16828 dated 10/25/97,to prior to entry into Mode 4.
ACR M3-97-0340 was generated as a result of this discovery. It identified 5 corrective actions, later expanded to 6, as follows:
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44 (1) Revise Cal::ulation NSP-098-FWA, Rev O, CCN 1 to reflect the correct usable, analyzed and instrument uncertainty volumes pertaining to both the indicators and the alarm switches.
(2) Review the revision to NSP-098-FWA and implement a design modification, if required,
to change the alarm switches setpoints and indicators scaling.
(3) Revise SP-ST-EE-286 or create a stand-alone document which establishes policy for identifying application of instrument uncertainties for TS LCO parameters.
(4) Review TS and identify systems which utilize control room instrumentation to comply L
with plant TS LCO values including (but not limited to) DWST, CST, Boric Acid Storage
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Tanks, Refueling Wder Storage Tank, Steam Generator Level, Pressurizer Level, Accumulator Level, Flood Protection, and Reactor Water Level.
-(5) Initiate revisions to TS, procedures, and related engineering calculations, identified in #
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4 above, to ensure verbatim compliance with TS requirements can be achieved, and define " contained" and " indicated" terms if required.
(6) Schedule a self-assessment to identify and perform an effective review after the implementation of the above corrective actions to assess the adequacy of these actions
- to prevent recurrence.
b.
Observations and Findinas
'The inspector reviewed the above described ACR and agreed that these were all of the appropriate corrective actions indicated by this finding. However, only the first five were considered as required in order to close out this concern from the NRC's perspective.
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The inspector reviewed revised Calculation NSP-098-FWA, Rev 2,8/8/97, " Demineralized Water Storage Tank Level Setpoint and Loop Uncertainty Calculation", which addressed all
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of the factors affecting the available RWST volume, such as AFW pump suction nozzle locations, vortexing, and instrument uncertainty, but identified some discrepancies that needed to be addressed further by the licensee.
Additionally, Calculation NSP-098-FWA, Rev 2, determined that the DWST level indicators 3FWA*Ll20A&B were not sufficiently accurate to support the surveillance for Technical
~ Specification 3.7.1.3. In response to this finding, DCR M3-97061, Rev 1, "DWST Level Indication Modification", was issued to add computer points 7493 and 7497 to monitor DWST level. The instrument uncertainty associated with these computer points was less than the originally installed level indicators and provided sufficient uncertainty reduction to make them suitable for TS surveillance.
This calculation also determined that the existing instrument loops could not read DWST
~ level to the minimum values depicted on the indicators due to sensing tap location. In response to this finding, this DCR also replaced the faceplate scales with new indicated ranges, recalibrates the level instrumentation for 3FWA*Ll20A1&2 and 3FWA*Ll20B1&2,
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and made corresponding adjustments to the DWST level alarm bistables to account for this respanning.
This modification was completed and accepted by the licensee on 11/18/97. It was reviewed by the inspector, and no discrepancies were identified.
~The licensee generated Engineering Evaluation M3-EV-970256,Rev O,1/25/97,
'" Determination of the Need to Apply Instrument Uncertainty to Technical Specification LCO Volume Surveillance Procedure Acceptance Criteria". This document assessed the appropriateness of the surveillance procedure acceptance criteria for the other TS LCO volumes with regard to instrument uncertainties and other factors. Included were boric acid storage, RWST, steam generator level, pressurizer level, RCS accumulator volume,
' DWST and DWST + CST volume, EDG fuel oil day tank and storage tank, and spent fuel poollevel. In all cases it was found that the acceptance criteria were conservative and provided sufficient margin to account for instrument uncertainty where required. The inspector also reviewed this document and identified no discrepancies.
As a result of Calculation NSP-098-FWA, Rev 2, the licensee concluded that the Technical Specification 3.7.1.3 requirement that the DWST contain at least 334,000 gallons of water was correct, but that it required wording clarification and its bases required additional -
information for clarity. These changes were initiated by the licensee with PTSCR 3-18-97 and were requested of the NRC in letter number B16532, dated 6/19/97. License
' Amendment No.150 was issued on 9/11/97 making these changes.
The effect of the Bases wording change was to clarify that the 334,000 gallon limit was a measured limit, and that it contained allowances for unusable volume due to tank nozzle locations, other tank characteristics (such as vortexing), and surveillance measurement
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instrument uncertainties.
Changes were also made in " Mode 1-4 Daily and Shiftly Control Room Rounds", OPS Form 13670.1-1,to clarify that the DWST volume data was to be based on readings from the process plant computer and to OP 3353.MB3C to refer to Technical Specification 3.7.1.3,
" Demineralized Water Storage Tank" for the LCO at any time there was an annunciated process plant computer failure. The inspector reviewed the documentation associated with this Technical Specification change and found no discrepancies.
c. Conclusions initially, the' inspector reviewed the corrective actions delineated in LER 97-019-00 and found them acceptable, except for some apparent calculational discrepancies. Calculation NSP-098-FWA for the DWST instrument uncertainties had been revised, but it contained discrepancies that still left questionable whether the current Technical Specification requirement that the DWST contain at least 334,000 gallons of water for Modes 1,2, and 3 was adequate and whether the instrumentation earmarked to monitor this volume was y
adequate,' considering its uncertainty.
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. Subsequently, during this same inspection report period, another inspector reviewed
' licensee corrective actions to address the noted calculational discrepancies. The most important issue involved potential deficiencies in Calculation NSP-098-FWA, which if valid,
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would cast the developed estimates of the minimum DWST water volume to satisfy the technical specification requirement, as non conservative. Regarding the appropriateness of their methods, the licensee provided justification for the equations used to estimate the onset of vortex action and showed them to be equivalent to those of an accepted -
authority. Regarding maximum AFW flow rates, the licensee provided data to show that -
the flow rate, used as a basis in the calculation, is comparable to the maximum flow achievable with either the motor driven AFW pump or the turbine driven AFW pump with Ltheir associated flow control valves wide open.' These responses were considered acceptable and' support the adequacy of Calculation NSP-098-FWA.
F Other questions required the licensee to evaluate scenarios other than those formally considered. The licensee responded with the requested evaluations or with a basis to negate the need for the evaluation < The inspector considered these responses acceptable.
'I in conclusion, the licensee has provided acceptable responses to the questions raised during NRC review of the calculations used to address LER 97-019-00 and has-implemented acceptable corrective actions. LER 97-019-00is considered closed. Based -
- upon this review and conclusion, in conjunction with the previously inspected and
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- documented review of the TS and operational issues related to this area, SIL ltem 70 is hereby closed..
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'08.3 (Closed) eel 96-201-10: Quality Assurance Records (Closed - SIL ltem 82)
a. Insoection Scope (929011 l
Two technical evaluations, referenced in a Proposed Technical Specification Change
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Request, were determined to be neither retrievable nor retained within the licensee's QA records system. Failure to maintain records of activities affecting quality is considered a
. violation of.10 CFR Part 50, Appendix B, Criterion XVil, " Quality Assurance Records." The l
'.NRC has issued a Notice of Violation and Proposed imposition of Civil Penalties by letter i
dated December 10,1997 that includes this item with NOV letter unique identifier 04113.
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These items will be separately reviewed. (eel 423/96-201-10)
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. The inspector reviewed'the licensee's corrective actions to address the document control
' failure that resulted in the violation.
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b. Observations and Findinas
f During an NRC inspection team review of a TS amendment request, dated April 28,1995, l
'* Proposed Revision to Technical Specification Ultimate Heat Sink," it was noted that
. certain technical evaluations were referenced in the TS Change Form to support the requested amendment. They were identified as References C and D, but not attached to the Proposed Tech Spec Change Form (PTSCR) documenting the request. The evaluations were not entered into the licensee's document control system and were not defined in the licensee's QA program. When requested to retrieve the evaluations the licensee's only resource was to obtain copies from the originating engineer's personal file. The failure to
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maintain records of activities affecting quality was considered an apparent violation and eel 423/96-201-10was issued.
The licensee issued ACR M3-96-0911 and subsequent CRs M3-97 2338 and M3-97-2544 to address the issue. The immediate causal factor was the lack of any overarching procedure or guideline for technical evaluations (TEs). This was because TEs were
" considered to be qualitative rather than quantitative, and are prepared when it is unreasonable to use calculations." As initial corrective actions, the licensee prepared and i
issued Unit Procedure U3 RP-10, to control outgoing regulatory corresporedence processing and validation, performed engineering evaluation M3-EV-970206 of all completed PTSCRs since 1986, to ensure supporting documentation could be located in Nuclear Records, and revised Nuclear Group Procedure NGP 4.02, to establish a consistent process for the control of TEs. Subsequently, the licensee issued Regulatory Affairs and Compliance procedures RAC 02," Technical Specification Change Requests and implementation of License Amendments," and RAC 08," Regulatory Communications and Docketed Correspondence," superceding both U3 RP 10 and NGP 4.02. In addition NGP 5.31,
'" Engineering Record Correspondence and Technical Evaluations," was revised to further define TEs.
The inspector reviewed procedures RAC 02, RAC 08 and NGP 5.31. RAC 02 defines the process for the initiation, review and disposition of TSCRs. It requires preparation of a 10CFR50.59 safety evaluation for all TSCRs and the transmittal of the TSCR package to Nuclear Records. RAC 08 provides the administrative process for handling docketed correspondence, it specifically states that validation is required for " material statements of fact used in all docketed correspondence" and provides guidance for the preparation of the validation package. NGP 5.31 specifies the requirements for the preparation and handling of Engineering Record (5rtespondence and Technical Evaluations. In this latest revision it establishes a single pq t for t: development, use' and control of TEs. It includes the requirement that all TEt be sent to the Nuclear Document Storage Facility.
The inspector reviewed the results of engineering evaluation M3-EV-970206. The total population of PTSCRs from 1986 onward had been reviewed by the licensee for documentation completeness. Six packages were identified to lack documentation but were later (under CR M3-97-2338)found to be complete. The inspector reviewed a small, arbitrarily chosen sample of completed PTSCRs. For these the references listed were either national codes or retrievable licensee files. No technical evaluations were on the reference-lists. These PTSCRs had been reviewed by the licensee in the performance of the mineering evaluation and the inspector's observation is consistent with the licensee's findings.
c. Conclusions t
The identified document control deficiency involved the handling of technical evaluations which, by the licensee's observation, were considered to be on a lower tier than quality documents. The new and revised procedures, issued by the licensee, raise the level of the TE to a quality document and provide detailed instructions for their development and use.
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Regarding PTSCRs, the new procedures require a safety evaluation, rather than a technical
evaluation, to be performed for each change request. This provides an additional j
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administrative buffer to prevent recurrence of the problem. The administrative measures taken by the licensee are deemed adequate. The technicalissues associated with eel 423/96-201-10are considered closed. The NRC Notice of Violation (NOV -letter unique identifier 04113) currently remains administratively open. SIL ltem 82 is hereby closed.
kl3.Il Maintenance U3 M1 Conduct of Maintenance M1.1 (Closed) Inspector Follow-up Item, IFl 423/97-02-15: SWP Relief Valves, Material Control and Lock Wires a. Insoection Scope (92902)
IFl 423/97-02-15 identified questionable certification of replacement parts for Service Water System relief valve 3SWP'RV96A, and missing lock wires in several other relief valves. The scope of this inspection was to verify the licensee's corrective actions to -
resolve these issues.
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. b. Observations and Findinas CR M3-97-1089, describes that Purchase Order # 936752 (dated 10/24/91) procured and purchased nine stock codes (391-461 through 469 for a total of 206 small bore pipe
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fittings) from Maritime Equipment Inc., a non-ASME supplier, for the Service Water System (an ASME Section 111 system). Thirty-three assorted fittings ordered were returned to the vendor and the remaining 167 fittings were received and erroneously identified as ASME material on the QA Acceptance Green Tag. On April 16,1997, a non-conformance report,
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NCR 397-06E was issued by the licensee. At the time of this finding, the Warehouse had
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already issued 146 fittings and the other 21 fittings remained in the Warehouse on
" HOLD". The licensee addressed this finding in two separate issues: the Code Case non-compliance which is addressed by CR M3-97-1089, and the material storage tagging issue which is addressed separately by CR M3-97-1442.
t For the Code Case non-compliance issue, the licensee performed a root cause evaluation by reviewing program procedures, historical documents (including Purchase Orders, memos, and Design Change Notices (DCN)), and regulatory positions (i.e., Code Cases, Regulatory Guides, and Generic Letters), and performing interviews with personnel from the Quality Control group, Warehouse, Engineering Programs, Design Engineering, and
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Licensing. No root cause analysis was used in this evaluation, since the severity of this
' issue was determined to be minor by the licensee. The contributing factor was the
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misinterpretation of the statement " intent of Code Case N-483 has been satisfied" on the l
Purchase Order, which was intended for clarification to the justification of the Design
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Change Notice (DCN DM3-S-294-91). The Code Case N-483 has not been approved for use by the NRC. The material should have been ordered with a reference to Code Case N-
? 245 which approves the use of ASTM B61 and B62 copper alloy castings for ASME
~ Section lil, Division 1, Class 3 construction.' NRC has approved Code Case N-245 for use in Regulatory Guide 1.85.
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At the time of procurement, the supplier (S.G. Flagg) could not supply fittings which would meet the original ASTM Specifications or ASME requirements. Commercial grade fittings E
built to Military Specification QQ-C-390 Alloy 92200 were purchased from Maritime Equipment Inc. Unit 3 Design Engineering was notified of the alternate material, and they
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1 initiated and approved DCN DM3-S 294-91 that equated the subject material specification
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and the approved _ ASTM material specification. The purchase order requirements mirrored l
.-the acceptance conditions of the DCN via the Commercial Grade Dedication process
without referencing the DCN number. The material in question is determined to be
i acceptable and meets the original design criteria (as documented in specifications SP-ME-
- 570, SP-ME-572) consistent with Generic Letter 89-09. The licensee has determined that i
' there are no operability concerns with this material (OD MP3-031-97).The confusion
- occurred due to lack of procedural guidance for.the use of Code Cases. Thus, with Unit 3 Technical Support approval, Procurement Engineering dispositioned NCR 397-062 as
" ADMINISTRATIVE".
Procurement Engineering issued a memo (PEG MP-97-0518 dated June 5,1997) to file referencing the Purchase Order (PO), Material Receipt inspection Report (MRIR) and identified the design basis for all fittings as DCN DM3-S-294 91 instead of Code Case N-483. The licensee updated Procedure NGP 6.02 to address the requirement that Code Cases must be approved by Design Engineering prior to use on Purchase Orders and
.. Design Control Manual (DCM) to address the requirement that Code Cases must be i
identified as " suitable for use" by the NRC prior to use as part of the design basis.
According to NCR 397-062,'the 21 fittings that were in the Warehouse on " HOLD" included six 1" 45'-elbows, eleven 2" tees, three 3/4" 90*-elbows, and one 3" coupling.
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With the closure of the CR, these components were again issued for use in the plant, and at present only four remain in stock.
With regards to missing reiief valve lock wires, CR M3-97-1006 has identified 13 out of 20 relief valves with missing or broken lock wires in the service Water (SWP) and Safety
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. Injection Pump Cooling (CCl) systems. At this time, the licensee has completed corrective i
maintenance on 12 relief valves and the work on the last valve is in progress. The licensee conducted field verification of all other relief valves (about 500 units requiring seals out of 670 inspected) in the plant to examine the conditions of their seal wires. As a result,
. forty-three (43) Trouble Reports (TRs) for relief valves found with missing / broken seal wires and five (5) Automated Work Orders (AWOs) requiring additional maintenance were
issued. The maintenance on all of these relief valves was completed. The inspector field verified a selected number of these units in the plant; no discrepancies were identified.
c. Conclusions
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The pipe fittings were originally installed as ASTM B61 or B62 material using Code Case N-245 as an alternative to the referenced ASME requirements. By approving DCN DM3 S-294-91, the licensee has established the equality in material specifications between these
ASTM materials and the materials in question. The inspector concluded that the corrective i
actions taken by the licensee are appropriate and therefore the Code Case non-compliance issue documented in CRs M3-97-1089 and M3-97-1442is considered closed. The inspector also verified the corrective actions taken by the licensee to resolve the missing i
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lock wires in all relief valves and found them acceptable. Therefore, IFI 423/97-02-15is closed.
M1.3 (Closed) Unresolved item URI 423/97-203-12:In-service Testina (IST) - Pump Testina Reference Flow Rates (Closed - SIL ltem 74)
a. Insoection Scope (92902)
The IST program was extensively reviewed and documented in inspection report 60-423/97-203. One inspector follow-up item from this review was evaluated and closed in inspection report 50-423/97-203,at which time the subject unresolved item on pump reference flow rates was opened. Subsequent to this latter inspection, the inspector raised several additional questions related to the IST program and SIL ltem 74 closure. During the current inspection, licensee responses to these questions were evaluated during an in-I office review by the inspector who had conducted the initial program inspection.
b. Observations and Findinas For the specific unresolved item on the adequacy of the licensee's practice for utilizing j
reference flow rates during IST pump testing, the inspector considered the licensee's documented position and the technical adequacy of a response to a Code inquiry, submitted to the appropriate ASME committee, on this subject. The inspector also reviewed and assessed the licensee's responses to certain technical issues involving relief valve setpoint temperature corrections, emergency diesel generator fuel oil test methods, l,
and check valve nonintrusive testing. An updated final safety analysis report change request FSARCR 98-MP3-403 was processed by the licensee to address an FSAR discrepancy questioned by the inspector. Additionally, the licensee indicated that any
additional scoping issues related to'the missed ASME Section XI service water system
' support examinations would be addressed, as applicable, by a supplement to LER 96-021.
The corrective actions relative to this LER were inspected and this LER was closed in l
inspection report 50-423/97-203.
- c. Conclusions
~ In-office review of the licensee's responses to NRC questions related to the overall adequacy of the IST program at Unit 3 identified no areas of continuing concern. A specific issue involving reference flow rates for pump testing was resolved and URI 97-203-12is considered closed. ' Closure of this item, along with the acceptability of the licensee's positions on other issues raised by the inspector, provide evidence that all
. identified IST program discrepancies have been adequately addressed. Therefore, in conjunction with the inspection reviews of the IST program documented in inspection reports 50-423/97-202 and 97-203, SIL ltem 74 is hereby closed.
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U3 M2 Maintenance and Material Condition of Facilities and Equipment
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' M2.1 (Closed) eel 96-201-34 Untimelv Evaluation of Service Water Performance and Heat Exchanaer Performance (Partial - SIL ltem 36 )
a. Inspection Scone (92902)
The NRC reviewed Plant Design Change Request, MP3-94-122 for 3HVR* ACU1 A/B,
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" Service Water Cooling Coil Replacement," Revision 0, to verify correct implementation of the replacement of coils in the MCC/RCC coolers. The coils were repicced because of leaks at the tube joints. The purchase specification for the coils did not specify thermal performance shop tests. The post-modification test requirements. stated that the " cooling coil heat transfer performance shall be verified... after startup from RF05."
The replacement coils were installed during refueling outage RF05 in May 1995. However, a thermal performance test was not conducted until December 1995. In addition, although flows and temperatures were obtained during the December 1995 test, the NRC noted that j
' no analysis or evaluation of the data was completed by May,1996. The NRC considered the 6-month delay in conducting the heat transfer performance test and the additional delay in evaluating the test data to be a weakness in the licensee's post-modification test i
process. The NRC's review of the test data found that the test data differed significantly
from the purchase specification, necessitating the need for analysis of the test data. The
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failure to adequately and promptly evaluate the test data to assure that the design change I
was properly implemented was a violation of 10 CFR Part 50 Appendix B, Criterion XI,
" Test Control" b. Observations and Findinas The inspector reviewed relevant engineering drawings and associated materials and the following specific documents; ASME OM S/G-1994 Standard Part 21 entitled " Inservice Performance Testing of Heat Exchangers in Light-Water Reactor Power Plants," NRC Generic Letter 8913 entitled " Service Water System Problems Affecting Safety-Related Equipment," the licensee document entitled "GL 89-13 Service Water System Heat Exchanger Performance Monitoring Program," Calculation 96-006 entitled "MP3 Air Cooling Unit 3HVR-ACU PROTO-HX model Development and Thermal Performance Test" and Calculation 90-069-1065M3" Service Water System-NRC Generic Letter 89-13, Item 13 No. IV Design Basis Summary Report."
Calculation 96-006 used empirical data to develop an analytical model of the Rod Control Air Conditioning heat exchanger Unit 3HVR*ACU1 A. This heat exchanger was the subject of eel 96-201-34. -The test of the heat exchanger consisted of measuring operating temperatures, pressures and flow rates for service water, the air duct flow temperature and relative humidity while the heat exchanger was under a heat load which approached the accident heat load. The apparent overall fouling factor was calculated from the test data obtained from this heat exchanger.
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c. Conclusions I
The calculation 96-006 demonstrated that, after the cooling coil in heat exchanger 3HVR*ACU1 A had been replaced, the fouling factor was acceptable. The test data taken from the 3HVR*ACU1 A heat exchanger and the calculations made from the test data, established an acceptable baseline capability of this particular heat exchanger. The
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technicalissues associated with eel 96-201-34 are considered closed. The NRC Notice of l
Violation (NOV - letter unique identifier 04073) currently remains administratively open.
M2.2 (Closed) Heat Exchancer Performance: Generic Letter 89-13 and ACR M3-97-0216 (Closed - SIL ltem 36)
Discussion / inspection Details (92902)
Generic Letter (GL) 89-13 was issued by the NRC to discuss problems with service water l
(SW) systems and to establish a recommended program that would ensure SW systems
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can meet regulatory requirements and properly remove heat from safety related components. This SIL ltem was previously reviewed in IR 423/97-207.- The open areas are addressed herein.
The GL states that it applies to any systems that transfer heat from safety related j
components to the ultimate heat sink. Intermediate systems used to transfer heat are also
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included in the scope of the GL. However, intermediate systems can be classified as
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closed cycle systems and thus not subject to all parts of the GL, if they are not subject to i
significant contamination, have their water chemistry controlled, and do not directly reject heat to the heat sink. Two systems were noted to be in question: 1.e., the closed cooling water systems for the charging pumps (CCE system) and the safety injection pumps (CCl-system).
l The inspector noted that these systems are filled with water from the RPCCW system but that the water in CCE and CCI itself was never sampled or chemically controlled after l
l addition. The licensee then sampled the systems and found the levels of corrosion inhibitor
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.very low; CRs M3-97-3501 and 4346 were written. Per the corrective action plans for
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l these two CRs, the licensee is in the process of establishing corrosion control via hydrazine addition for the CCE and CCI systems. This is currently scheduled for completion before plant startup. This will be tracked as IFl 423/98 207-14.
l Item 1 - Surveillance and controls to reduce flow blockaae due to biofoulina item I. A - Intake structure GL 89-13 calls for inspections of the intake structure for biological fouling, sediment, and i
corrosion; it also specifies that any fouling accumulations should be removed. The licensee
has committed to annual inspections by divers and/or videotape, refurbishment, removal of all debris from the bay, and cleaning. The licensee revised Procedure EN 31084 to address the previously identified concerns. The licensee also hired a contractor to inspect, clean I
and repair the intake structures. The inspector reviewed the report of the underwater
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cleaning, dated November,1997 - January,1998, which included before and after photographs. This report showed acceptable results.
Item 1 B - Chlorination
'This item of the GL calls for continuous chlorination of the SW System. The licensee has committed to continuous chlorination and to regularly scheduled thermal backwashing of the circulating water (CW) system to also clean the intake structuri, bays. They also have stated that they take daily samples of free available chlorine (FAC) and make reports to management to ensure prompt action if measurements drop below an effective level.
Chemistry takes a daily sample of the SW chlorination per procedure CP 3804AG. The results are logged and included on the daily status reports.
The inspector previously noted some procedural and implementation problems with procedure CP 3804AG. The procedural controls were weak in that there was no clear lower acceptance criteria for FAC, there was no lower value of FAC on the data sheet, and the data sheets were not being circled or annotated when FAC was out of specification low. The licensee revised the procedure; however a review of the logs for March and April showed that log keeping practices remain weak, in that the data sheets are still not being circled or annotated when FAC was out of specification low. Also, there were a variety of times between samples when FAC was low from about 20 minutes in some cases up to about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in other cases. From previous testing, this amount of time should not permit mussel attachment, however, practices should be improved. This will be tracked as part of IFl 423/98-207-14.
Item I. C - Flushina, flow testina, and lavuo This item of the GL calls for flushes and flow testing of infrequently used SW loops. It also calls for testing of other SW components on a regular schedule to ensure they are not fouled or clogged. Further it adds cautions about layup of idle SW loops. The following problems with this item were noted previously.
The post-accident sampling system (PASS) coolers are normally isolated and drained. They are functionally operated by taking a sample every six months per procedure SP 3885i however, there is not 'a full flush and no flow test. The licensee revised SP 3885 to record the SW differential pressure (DP) to the PASS loop as an indication of flow during each test sample. The SP also now specifies that the DP data be forwarded to Technical
' Engineering for trending. During the recent performance of the PASS sample test, the licensee noted that the 3SWP-PDIS163 was not functioning and hence could not record the DP data. A Trouble Report (TR) was written. The proper flushing and flow testing of the SW loop to the PASS coolers will be addressed as part of IFl 423/98-207-14.
The spent fuel pool cross-connect line has a spool piece removed, then two closed isolation valves to the SW system. The line between the valves is drained. There is a dead leg of several feet between the SW line and the first isolation valve 3SWS*V700.
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During refueling outage No. 5 an inspection found some mussels in this dead leg. This was cleaned and a modification (EWA 93061) scheduled for the next refueling to move the isolation valve closer to the SW header in order to rninimize the dead leg. Additionally, the
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- AFW dead legs run from one elevation in the ESF building to the next and between compartments. They are quite long and are not on a regular inspection program. The licensee wrote AR 98007826to ensure that the AFW dead legs and the dead leg next to valve 3SWS*V700are inspected at the next significant SW system outage. The licensee also issued AR 98007827to incorporate these inspections into procedure EN 31084.
These activities will also be verified as part of IFl 423/98-207-14.
Each SW train has two SW pumps, with only one running at a time. When a pump is secured, its discharge valve is shut, leaving a dead leg between the pump discharge check
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i valve and the discharge isolation valve, that also needs to be considered. The licensee rotates the SW pumps monthly per the SW pump surveillance tests. Also, these lines were inspected as part of the SW system inspection program and no fouling was observed.
'i There have been no recent reports of fouling of these portions of lines. This is acceptable.
I Item II - Test oroaram for heat exchanaer (HX) capability
GL 89-13 calls for a test program to verify HX capability of all safety related HXs cooled by service water. Enclosure 2 to the GL provides an example of an acceptable program.
Alternative, but equally effective programs are permitted.
The licensee has sent numerous response letters to the NRC that concern item II. The
' inspector noted that the aggregate of the responses was confusing, inaccurate in places, and did not appear to meet the intent of item 2. The inspector noted that a revised, consolidated, and updated response to the NRC to item 2 would be appropriate. The licensee submitted an updated response on May 6,1998, by letter B17205. This response will be reviewed by the NRC Office of NRR.
The inspector reviewed the licensee's test program entitled, "GL 89-13 Service Wa'ter System Heat Exchanger Performance Monitoring Program," Rev. O, dated January 19, 1998..This document described a scheme of monitoring and evaluating SW system heat exchangers which was designed to comply with the NRC GL 89-13.- The monitoring
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program relied upon Part 21 of the ASME OM-S/G-1994 Standard. The Part 21 Standard I
and GL 89-13 allowed certain small heat exchangers such as lube oil coolers to have their
" function verified" instead of being tested. The licensee procedure provides an initial test
of all safety related "open cycle" heat exchangers and then takes full advantage of -
verifying the function of the small heat exchangers. Verifying the function of the heat-exchanger means that the item, which the heat exchanger is cooling, is cooled within design conditions. The inspector had previously noted that the program probably needed to be extended to the CCE and CCI systems based on inadequate past chemical control of L
these two systems. The licensee has included thes'e HXs into their GL 89-13 HX test i
program. The licensee's monitoring program provides guidance as to when component
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testing is required, guidance on standard test methodologies, analysis of test data, and instructions for record keeping. The licensee document, "GL 89-13 Service Water System Heat Exchanger Performance Monitoring Program," Rev. O, in conjunction with Part 21 of ASME OM-S/G-1994 Standard adequately describes an " upper tier" technique of testing and monitoring safety-related SW system heat exchangers per GL 89-13.
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The inspector also reviewed the test results from the approved test program. The heat exchangers tested to date are: 1) the two Emergency Diesel Generator coolers, 3EGS*E1 A/2A and 3EGS*E1B/2B; 2) the Containment Recirculation Pump cooler
. 3HVQ' ACUS 2B; 3) the Safety injection Pump cooler 3CCl*E1 A; 4) the Charging Pump coolers 3CCE*ElA/1B; 5) the Control Building Air Conditioning Water Chiller 2HVK'CHL1 A; and 6) the MCC & Rod Control Booster Pump cooler 3HVR*ACU18. The performance testing is designed to demonstrate that the heat exchangers can meet their Design Basis Limits as well as to determine how often the heat exchangers must be cleaned. ; The listed HXs were selected for testing by a priority and similarity process that is covered in Part 21'of the ASME OM-S/G-1994 Standard.
? The inspector reviewed the relevan' engineering drawings and associated materials as well t
.as the test procedures and the results of the' performance test for each of the heat exchangers listed above. The listed heat exchangers were specified by the licensee to be tested prior to the startup of Unit 3. The remainder of the untested heat exchangers will be tested at a later date. The list of HXs tested now, those scheduled for later testing, and the justification for the schedule is included in the updated response letter for GL 89-13, noted above. The performance testing of the heat exchangers caused the licensee to make a number of changes and corrections to the calculations relating to the Service Water
- System Heat Exchanger parameters.'These changes related to heat load, flow rates, fouling factors, maximum percent of heat exchanger tubes allowed to be plugged, service water outlet temperatures and other similar parameters. All of the tested heat exchangers met the design parameters with a 95%' confidence level; however, a number of them did so with a very small margin. Some of the heat exchangers when subjected to a performance test at the postulated lowest design flow allowable met their design requirements with only a few percent of excess flow rate. The performance testing identified that the EDG heat exchangers were experiencing a fouling rate that was predicted to reach unacceptable
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limits on November 11,1998, or when the' sea water in Long Island Sound reached 71
. degrees F. The licensee has written an operability determination for these HXs and has scheduled another test for after the Long Island Sound heats up in the early summer. This j
test should provide a demonstration that the HX can perform at higher temperatures and also give another data point for a better extrapolation as to when fouling will become unacceptable. These are being tracked on the CR and ARs for this item.
.The test results of the identified heat exchangers and the resulting analysis of the test data l
. was found to be adequate to substantiate the licensee's assertion that the heat exchangers
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tested have the capacity to perform their safety related tasks.
Item lli - Routine inspection and maintenance oroaram i
ltem IV - Confirmation of licensina basis
. Item V - Confirmation of maintenance /ooeratino oractices and trainina These three items were acceptably reviewed in IR 423/97-207.
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- Conclusion SIL ltem 36, addressing Generic Letter 89-13 and ACR M3-97-0216,is closed.
Certain licensee corrective measures and program improvements are issue that will continue to be tracked as an inspector follow-up item, IFl 423/98-207-14which is hereby opened. These issues are: CCE/CCl system corrosion control, SW Chlorine monitoring and log keeping practices, the proper flushing and flow testing of the SW loop to the PASS L.
. coolers; and proper inspection of the spent fuel pool cross-connect line and the AFW cross-
. connect dead legs.
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t U3 M3 Maintenance Procedures and Documentation
. M3.1
. MEPL Proaram Review (62702)- (Update - SIL ltem 25)
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- 1. - Site Level MEPL lssues L
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t The overall site material, equipment, and parts lists (MEPL) program was reviewed in irs.
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~ 423/97-202and 423/97-203; comments and discussion that apply to all three units are
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provided here.
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Four issues were identified in IR 423/97-202 with respect to the site level program, as followsi (1) There has been an historical question of the potential to have nonsafety-related (NSR)
parts installed in safety-related (SR) components. This has been~ documented on a number of ACRs and CRs for each unit. This has been separately addressed by each unit and the status is discussed in the section for that unit.
H (2) Specification 944 does not check for the impact on NUQAP, Appendix A when l
downgrading a component from SR to NSR. Any changes to NUQAP that reduce-k'
commitments (e.g., the list of SR items) require prior NRC approval per 10 CFR 50.54(a).' The licensee issued Change #5 to Specification 944 that would require a review of the NUQAP for any reduction in commitments whenever a MEPL evaluation
- downgrades a component or part from SR. The inspector reviewed the change and found it addressed the concern. This is acceptable.
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. (3) NRC' raised a concern that the MEPL procedures did not adequately consider normal l
operations and anticipated operational occurrences (AOOs) as part of the " design basis events" to be considered when making safety-related classifications under the MEPL
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program. : Discussions with NU managers responsible for the MEPL program stated that earlier. versions of the procedure / specification did refer to normal operations and AOOs,
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' but that Rev. 3 of Spec. 944 removed this specific reference. The intent of the current program, under Rev. 4 of Spec. 944,is that engineers performing MEPL evaluations must still consider normal operations and AOOs as part of the " design basis events" in
- making safety-related classifications. Step 5.2.2.4 of Spec. 944 states that guidance
- can be found in EPRI NP-6895. Page 4-2 of NP-6895 contains a definition of Design Basis Events that includes normal operations and AOOs, as well as other items. This L
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indirectly addresses the concern; however, the inspector noted that personnel performing evaluations will not usually have or reference the EPRI document. The licensee agreed to modify Spec. 944 and again directly include normal operations and AOOs. This was accomplished as part of Change #5 to Spec. 944. This is acceptable.
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. (4) The PMMS database is not complete. This discussion here pertains only to the Unit 3 status and is discussed in the Unit 3 MEPL section.
' During IR 423/97-203the inspector noted an issue with control of consumables, as follows. There is currently no effective method for tracking MEPL status on conramable items, and ensuring that any requirements established in the MEPLs are met during the.
purchasing and use of the item. The resolution of this item will be discussed for each Unit separately. Thus, all site level issues have either been addressed or will be covered on a unit-specific basis.
. 2. Unit 3 MEPL Prooram implementation During IR 423/97-202,the implementation of the_ Unit 3 MEPL Program was reviewed.
.The inspector noted the below five issues, which have been addressed as follows. Also addressed are two other items identified for Unit 3.
-(1) Documentation of Safety Function: In order to properly classify an item in the MEPL Program, the safety function must be clearly understood. The latest Rev. of Spec. 944 requires this to be determined and documented in the MEPL evaluation. The earlier
~ versions of Spec. 944 also recognized the importance of determination of safety.
function, but were not as specific in the procedure. The MEPL evaluations reviewed
. did not always clearly document all of the safety functions.
The licensee noted that while the identification of the safety function is important, the key point in the MEPL process is the overall quality classification. Thus, partial
. documentation of safety functions is only a problem if it leads to incorrect k
classifications. In the various numbers of MEPLs reviewed, the inspector did not identify any incorrect classifications. The licensee also noted that the system level MEPL process was a one time effort. Further, for the parts level reviews, the generic MEPLs are often used which are conservatively based on the most restrictive function of the component. A thorough and documented review of completed MEPL packages during the current process helps to avoid missing any safety functions. As far as ongoing MEPL evaluations in the future, the licensee drafted Non-Intent Change #7 to
. Specification 944 to clarify that all safety functions must be identified. This added
changes to Section 5.2.1 and Figure 7.3 to address this concern. This is acceptable.
(2) Listing of Design documents:: The MEPL evaluations reviewed did not list all of the pertinent design documents and FSAR references on the MEPL determination, Figures 7.3 or 7.4 (example, CVCS System MEPL). The licensee noted that the intent of MEPL Spec. 944 is to list all necessary documents rather than all possible documents. The MEPL is not intended to encompass all documents related to a particular component, but only to refer to those documents needed to clearly and unequivocally provide a
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basis for the MEPL conclusions. The inspector did not identify eny cases where lack of documents resulted in improper MEPL classification conclusions. This is acceptable.
(3) PMMS Identification Numbers: The numbering scheme for PMMS results in differences between the ID for components in the field /on drawings and in the PMMS database, when the, number of characters exceeds 15. The licensee performed a review of the PMMS database and found that there were 392 Cat.1 ids that have been reduced from their full 10. They further reviewed and categorized each item as to what was
. removed to reach the 15 character limit. Most changes were trivial and not of concern,
. but there were about ten that had the * dropped, creating the potential for mistaking a SR item for NSR. The licensee is still evaluating how to address these components.
This item is still open.
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(4) Designation of Safety Related components with an asterisk *: FSAR, Figure 3.2.2 stated that an asterisk * indicates that equipment is quality assurance Category 1 (i.e.,
SR). However, the inspector noted that: ' not all SR components use the * as noted in the FSAR, e.g., SR snubbers; there is some ambiguity in the use of the * for relays; and some ID tags and signs in the plant do not use the *, even though the component is SR and the * is used in PMMS. The licensee noted that in accordance with the plant's original identification convention, there are a small number of types of components that may be SR, yet not use the * in their ID. The licensee issued FSAR Change Request No. 98-MP3-2 to revise the FSAR to accurately reflect the actual plant practice as defined in their specifications. The licensee also issued Specification SP-M3-ME-024, Rev. O, Conventions for System identification, System Interfaces, and
' Equipment Identification, that currently defines in detail the conventions used to establish and maintain system and equipment identification for MP3 systems, structures, and components. The inspector noted that not all component ids -
. conformed to the new' Spec. The licensee is evaluating actions.
The inspector toured the plant and observed a number of components and their labeling, then compared these label ids to that in the PMMS and MEPL systems. Two items were noted with no labels and two items with only the old style labels. A valve,
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3CCP*LV91, was noted that had both a new label with an asterisk (*) and an old label with a dash (-). Thc licensee's label group corrected these items. The inspector noted that there do not appear to be labels on Appendix R lights or electrical components in
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. the plant that correspond to anything in PMMS or the new Specification 024. A check l
with PMMS turned up the following: four NSR components not in PMMS, one SR-l I
Junction box not in PMMS, unable to locate all components for fire protection (such as emergency lights) in PMMS, the emergency lights found in PMMS'did not have the same ids in the plant as in PMMS, and snubbers not labeled with * and not merged i
L into Unit 3 PMMS system. Near the end of the inspection period the licensee began l
work to correct the labeling discrepancies with fire protection equipment. Other components will be addressed separately. This item is still open.
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(5) Human Factors Painting issue: While performing the MEPL-related plant tours, the i
inspector noted that some orange or A Train components are being newly painted i
purple (the color of the B train), e.g., OSS pump and AFW pump. This created an
' increased potential for " wrong train" type of human errors. After a period of time, the e
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licensee repainted the components so that the trains do not use the incorrect train color. They also added orange and purple colored stripes on the walls of the ESF
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Building to properly denote the A and B trains. This is acceptable.
(6) The PMMS database for Unit 3 was noted to be incomplete. Some SR components are not in the MP3 database, e.g., snubbers. Many augmented QA and NSR parts and components are also not in the databrse. This was still the case during this report period. The concern is _that an incomplete database may result in work of the incorrect quality level being performed, since the PMMS database is used extensively onsite for checking the status and classification of components. However, NGP 6.10, Step 6.4.1, now requires that all parts and components either be treated as QA Category 1 (safety -
related) or that there be an' approved MEPL evaluation that classifies it as nonsafety related.' Also, MP3 has assignments (ARs) to add the snubbers to the MP3 database and to add all augmented QA components by December,1998. The licensee has -
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stated that they will meet this date and have the PMMS database updated to contain all
- MP3 safety related items (including snubbers) and all augmented quality items by the end of 1998. This is acceptable.
A related issue was noted in'the response to NOV 04043 that states that one hundred percent of the MS Unit 3 components in the PMMS database were reevaluated for the proper quality category. However, in order to adequately address some of the MEPL concerns, it is important to reevaluate all components (in the safety related and augmented quality categories) for the proper quality consistent with plant design and licensing bases. Therefore, the inspector questioned whether those items not in the
_ PMMS database had been so reviewed and, if not, when they would be. The licensee had not responded by the end of the inspection period.
(7) During IR 423/97-203,the inspect'or noted an issue with control of consumables.
There is currently no effective method for tracking MEPL status on consumable items, and ensuring that any requirements established in the MEPLs are met during the purchasing and use of the item. The Hard Copy MEPL, which is used for items that do
, - not have a specific component ID (such as consumables,) has not been kept up to date.
The licensee stated that the MEPL program would be updated to appropriately address the consumable items. They also stated that the information from the MEPL evaluations, the CCPL, and from Procurement would be properly integrated, and that the MIMS system _would be updated to track any MEPL requirements for consumables to ensure that they are addressed when purchasing the consumables. In 1998, the
- licensee performed a further review in this area, identified ongoing consumable problems and. issued CR M3-98-0407. The CAP for CR M3-98-0407is extensive, containing 32 items, and was still being implemented at the end of the inspection period. This item is still open.
(8) Previous problems were noted with the MEPL evaluations and PMMS entries associated with the Unit 3 Containment Hatch in Unresolved item 423/95-07-10. The licensee
- was still reviewing the revised MEPL evaluations at the close of the inspection period.
This item remains open.
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3. Review of eel 96-201-43 and ACR M3-96-0912. Inadeauste closure of MEPL related NCRs ACR M3-96-0912 addresses eel 423/96-201-43. The NRC subsequently issued a Notice
l.
of Violation and Proposed imposition of Civil Penalties by letter dated December 10,1997
'
L that includes this item with NOV letter unique identifier 04043. NU subsequently l
responded to this NOV with letter 816996 dated March 2,1998. Page 129 of this response letter addresses NOV 04043. The response to NOV 04043 will be separately i
reviewed.
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i This item addressed MEPL problems at both MP2 and MP3.' The item identified that NU
' procedures did not provide guidance regarding the criteria to be used in evaluating the adequacy of installed non-QA materialin safety-related applications. This was determined to be a principal factor in MEPL-related NCRs that were closed without adequate written
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justification. The licensee wrote ACR M3-96-0912 to address this item and included a number of specific items in the corrective action plan. The inspector reviewed these actions as noted below.
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Specification SP-ST-ME-944; Standard Specification; Material, Equipment, and Parts Lists
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for in-Service Nuclear Generation Facilities (MEPL program) was revised to clarify the design / licensing basis interfaces and the_ use of NCRs in the MEPL program. NGP 3.05
Nonconformance Reports, NGP 6.01, Material, Equipment, and Parts Lists for in-Service nuclear Generation Facilities, NGP 6.05, Processing and Control of Purchased Material,
. Equipment, Parts, and Services, and NGP 6.10, Use of the PMMS ID-System and BOM Database have also been revised and updated. NCRs are now required whenever a component or part is upgraded from NSR to SR. NGP 3.05, Nonconformance Reports, was revised (Step 6.1.6) to require a CR be written on _NCR origination. The CR will establish
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ownership and timeframe for resolution and will require trending and preventive actions as
- appropriate. lt will also address operability and deportability issues. NGP 6.10, Step 6.4.1,
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requires that all parts and components either be treated as QA Category 1 (safety-related)
or that there be an approved MEPL evaluation that classifies it as nonsafety related.
Over the 1995 and 96 timeframe Unit 3 performed system level MEPL evaluations of all (145) systems and hence all components in the PMMS database. Component and part upgrades were identified and NCRs, associated with these upgrades, were generated. The inspector reviewed a sample of these NCRs and noted that they were dispositioned appropriately.
. The licensee also performed an historical review of MEPL-related NCRs to see if they had been properly closed. _ Of the review of 326 NCRs, only two were found that potentially made a change to a component with a design change. For these two NCRs,it was determined that there was no adverse impact on operability. Minor modification, MMOD M3-96576, was issued on 12/24/97 to consolidate and resolve documentation
- discrepancies that resulted from administrative MEPL reclassifications.
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Despite the above, the inspector noted additional problems at Unit 2 with MEPL-related
NCRs in the Fall of 1997;this is discussed in the Unit 2 section of this report. MP3 has
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not shown similar problems (with the exception of NCR 397-010, which is discussed
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. below), and is currently following the guidance in Spec. 944, Figure 7.7, which states all
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applicable design bases, licensing, programmatic requirements, and past maintenance work history and purchase history are to be evaluated by the NCR. The issues associated with
'NCR 397-010 are addressed as noted below in subsection 6. With regard to the MP3 MEPL issues and corrective actions taken in response to inspection report 50-423/96-201, eel 423/96-201-431s considered closed.
4. Issue of Nonsafetv-Related Parts in Safety Related Components The issue of NSR parts in SR components has been raised by. previous NRC inspections and by a number of internal CRs, engineering reviews, and oversight reviews. MP3 has performed various reviews over the last two years to address the concern. They have also identified some problems as a result of these reviews and taken corrective actions. The -
inspector reviewed Technical Evaluation for Acceptability of installed Parts and Materials in Maintained QA Category I plant Components, MP3, M3-EV-98-OO22, Rev.1, March 12, 1998, which summarized the various activities taken to address this concern.
In order to address this concern the licensee considered all of the approximately 19,000
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safety related (SR) ids in the PMMS system. About 1,000 of these ids are not
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specifically components or would double count the components, such as system ids or i
l&C loops. Of the total of 18,000 SR components,13,000 had no work performed on
them since initial construction. These did not need further evaluation.
A SR component may have sub-parts, which are listed on a Bill of Materials (BOM). The average number of parts on the BOM of a SR component in Unit is about 15 parts and the maximum number is 500. These parts may be SR or NSR. About 1,000 components had i
either no sub-parts on their BOM or all SR Category 1 parts on their BOM. These
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compone'nts and parts were'thus adequately addressed and needed no further review.
-. Several hundred components were evaluated in 1997 in Engineering Evaluation M3-EV-970009 to verify that non-QA parts were appropriately classified and installed. The actual I
number was not clear and the inspector requested the licensee to clarify this item. These components were those associated with risk significant systems used for safe shutdown.
This effort did not perform a full MEPL evaluation for all parts in each BOM, but did evaluate existing installed parts for adequacy. No discrepancies were identified by the licensee in this review.
l About 2,000 components (primarily ASME code pumps and valves) were involved in a
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review and upgrade project. The inspector also requested the licensee to clarify the actual i
number of these items, because there was a discrepancy between the Technical Evaluation
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and.the related NCR. These items received additional licensee and NRC review as
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discussed in Subsection 6 below.' As noted there, CRs were written to address 29
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components that had NSR parts installed in SR components without the full documentation that would normally be available to SR parts.
Between 1,000 and 2,000 components, containing about 15,000 parts, remained to be reviewed in detail as part of the most recent MEPL/BOM effort. The existing BOMs for each of these components were printed out and the parts were reviewed to verify that any
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non-QA parts were appropriately classified and installed. As above, a full MEPL evaluation
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was not performed for all parts in each BOM, but the licensee did evaluate existing l
installed parts for adequacy.
l As a result of the above specific reviews, three parts on SR components were determined to be not acceptably addressed. Some additional parts in SR components were identified as needing rework, due improper or indeterminate quality, as part of ongoing maintenance activities. The inspector questioned the licensee as to the total number of these items that were identified through various activities over the last two years. CRs were written to address each of these items identified.
The inspector noted that the Technical Evaluation needed updating to address issues raised herein and below in Subsection 6. This item remains open.
5. Current Parts Control Issues The parts issuance portion of the program was not reviewed with the rest of the MEPL program in inspection report 423/97-202 due to ongoing issues identified by the licensee.
The licensee has taken various preventive actions through 1997 to address this concern.
This has resulted in increasing controls over time. Nonetheless, some individual problems continued to occur. Some reviews showed good performance (e.g., Oversight memo of January 10,1998 - sample of 13 work orders with no problems; Oversight memo of December 29,1997 - sample of 24 work orders with no problems), yet other reviews identified some ongoing problem areas (e.g., CRs M3-98-0407 and M3-98-0989). The corrective action plan (CAP) for CR M3-98-0407is extensive (32 actions) and proactive.
Many improvements, both short term and long term,in the ongoing parts issuance and installation process are being made. This item remains open.
6. NSR Parts Uoarade At the time of Unit 3 construction and initial operation, NU did not have clear guidance established for the safety classification of parts within SR components. Many of the parts were classified as a result of information originally obtained from the architect-engineer for the plant. For the ASME code components, the only parts that were classified as SR were the code parts (or pressure boundary parts). Thus, non-code parts such as lock nuts, actuator stems, capscrews, valve seats, etc. were treated as non-engineered, commercial, non-SR items. However, these parts, both original and replacement, were required by NU procedures to be bought and installed to the component specifications and drawings.
On December 8,1988, the NRC issued Information Notice (IN) 88-95, " inadequate Procurement Requirements imposed by Licensees on Vendors," which identified a problem whereby functionally important parts of safety related (SR) ASME Code components were not treated as SR. The NRC also stated in the IN that it is important that licensees place adequate requirements in procurement documents to control the quality of SR components and that compliance with the ASME Code by itself is not always sufficient to ensure compliance with Appendix B. The licensee reviewed this IN, and identified some problems with their purchasing systems, did not address the above key aspects related to the
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appropriate application of QA parts within SR components. Thus, the licensee continued
- to list in their control systems, and to procure these parts as NSR, until 1997.
In,the 1990s Millstone upgraded their classification procedures to match the improving
' industry standards. Thus, they began to use guidance published by EPRI in NClG-17,-
. which uses functional requirements as a basis for classification as SR rather than simply code designation. As a result of this new approach, in 1997, the licensee upgraded about 15,000 parts, associated _with 2,000 SR components. A large portion of the components that had parts upgraded were ASME Code pumps and valves. - These parts were of the type noted above. As part of the MEPL evaluations that upgraded the' parts, the licensee reviewed the pertinent specifications to ensure that the parts were clearly defined in the specifications.. The licensee also wrote NCR 397-010 as a collector NCR to document and resolve this upgrade to all of these parts.
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Specification SP-ST-ME-944, " Standard Specification; Material, Equipment, and Parts Lists for in-Service Nuclear Generation Facilities (MEPL program)," Revision 4, 5/21/97, Figure 7.7, " Instructions for When a CR or NCR is Required," requires that all applicable design bases, licensing, programmatic requirements, and past maintenance work history and purchase history be evaluated by the NCR. However, a detailed purchase history review or -
_
work history review was judged by the licensee not to be necessary, since original and -
replacement parts should have been purchased and installed in accordance with the specifications. Nuclear Oversight questioned this determination and performed a small audit sampling of parts that were dispositioned under the NCR. This sample involved a work history review and field walkdown to determine if the correct parts, per the specification, had been installed. No discrepancies were identified by Nuclear Oversight in this small sample review. A CR was also issued by Nuclear Oversight, but the CR was
- dispositioned with the issuance of Technical Evaluation for Acceptability of Installed Parts and Materials in Maintained QA Category i plant Components, MP3, M3-EV-98-OO22, Rev.
1, March 12,1998 (discussed in Subsection 4 above).
The inspector noted that component and part-specific work history and purchase histories had not been performed and also questioned whether the licensee had reviewed the acceptability of spare parts in the warehouse that had been procured under the old program. -The inspector also contacted the. NRC Office of NRR and discussed this issue with them, regarding the acceptability of the process. NRR questioned the licensee's
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application of ASME Code Cases, Information Notice 88 95, Generic Letter 89-02, and Generic Letter 91-16.
Iln response to additional NRC questions, the licensee performed a detailed component and part-specific review for each of the items in NCR 397-010. For each of the 2431 components addressed in the NCR, the licensee printed out the affected, upgraded parts and all work orders (AWOs) that had ever been performed on the component. This was reviewed in deta!! and the licensee determined that: 978 components had no work performed on them; 1424 had acceptable work performed on them; and 29 components had work that clearly installed NSR parts in the SR components. The majority of the 1424 components that were judged to have acceptable work, had work that was done on the component, but did not affect the parts in the NCR. There were also 66 AWOs in this group of 1424 where the parts in question were replaced with SR parts even though at the
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time the PMMS carried them as NSR. Also, there were 22 AWOs in this group that replaced the parts prior to original plant startup under the architect engineer's OA program.
. The inspector reviewed a sample of the documentation for this portion of the review and
- noted that it appeared comprehensive The items that were replaced prior to original startup were noted to contain QA/QC attributes with the work packages.
With regard to the 29 components that had NSR parts in the SR components, the licensee wrote CRs and performed Operability Determinations (ODs) for sach of them. The ODs concluded that the components were still operable, in general these parts were procured from the original equipment manufacturer to the original specification. Also, the licensee
' was able to verify the following types of information for many of the 29 components (but not all of these aspects for every item): procurement documents / purchase requisitions, some QA review of AWO, proper part stock code numbers, materialissue forms (MIFs)
with proper number, drawings, maintenance performed to procedures, vendor calls,
- successful post maintenance testing, and successful periodic surveillance testing.
The inspector requested the licensee for a plan and schedule for bringing the 29 degraded / nonconforming items into full compliance with Appendix B requirements, as discussed in Generic Letter 91-16, Rev.1.
The identified concerns constitute a violation of 10 CFR '50, Appendix B, Criterion XVI,
'" Corrective Action," which requires, in part, that measures be established to assure that conditions adverse to quality, such as... defective' material and equipment, and nonconformances are promptly identified and corrected. Contrary to this, the licensee did not assure that conditions adverse to quality were identified and corrected, as evidenced by the following examples:
(1) On December 8,1988, the NRC issued Information Notice (IN) 88-95, " inadequate Procurement Requirements imposed by Licensees on Vendors," which identified a problem whereby functionally important parts of safety related (SR) ASME Code components were not treated as SR. The NRC also stated that it is important that licensees place adequate requirements in procurement documents to control the quality of SR components and that compliance with the ASME Code by itself is not always sufficient to ensure compliance with Appendix B. The licensee reviewed this IN, but
- did not address the above key aspects,in that approximately 2,000 SR ASME components in the plant had functionally important parts designated as non-SR from the time of originallicensing of the plant,'in 1986, until 1997. Further,29 of these components had non-SR parts procured and installed during this timeframe.
(2) Specification SP-ST-ME-944," Standard Specification; Material, Equipment, and Parts
. Lists for in-Service Nuclear Generation Facilities (MEPL program)," Revision 4, 5/21/97, Figure 7.7, " Instructions for When a CR or NCR is Required,". states in part that a nonconformance report (NCR) is required for MEPL classification upgrades from non-QA L '
or undetermined, to Category 1/QA and fudher states that all applicable design bases, licensing, programmatic requirements, and past maintenance work history and purchase
!
. history are to be evaluated by the NCR. Contrary to the above, NCR 397-010, g
addressing the MEPL upgrade of parts in 2431 components from non-QA or L
undetermined, to Category 1/QA, was approved on 2/9/98 without performing part-or
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component-specific maintenance work history and purchase history reviews. The upgraded parts were primarily contained in SR ASME code pumps and valves.
- 7. Summarv
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i SIL ltem 25 remains open, pending resolution of the above-noted issues, and is hereby updated. - The technical aspects of eel 90-201-43 are considered closed for Unit 3 only, The NRC Notice of Violation (NOV - letter unique identifier 04043) currcntly remains a
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. administratively open. An additional violation of 10 CFR 50, Appendix B, Criterion XVI L
was identified with regard to aspects of the NSR parts upgrade of the MEPL program, as
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documented above. (VIO 50-423/98-207-15)
l U3M8 Miscellaneous Maintenance issues
' M8.1 Vendor Interface Proaram Review (92QQ2) (Update - SIL ltem 18)
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The overall site program for Vendor Interface was reviewed in IR 423/97-203. Unit 3 issues that were identified are updated herein.
1. Proaram with NSSS vendor-l The inspector noted that the licensee had'not' routinely verified that they have received all
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-. technical information provided by the vendors. The licensee performed a review and found p
- that NSE had not received some recent CE Infobulletins and that recent Westinghouse i.
Infograms had not been input into the assessment process. As a result, CR M1-97-1914 l
' was issued. The licensee performed an historical review to identify any missing documents L
and input them into their system. Alsoi procedure NSE 1, implementation of Operating Experience, was issued that includes an annual review of' vendor indices to ensure that all documents have been received. The licensee is verbally contacting the NSSS vendor approximately quarterly.for updates. NSE 1 also specifies an annual search of various
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- external databases to ensure all pertinent Part 21 reports have been received and reviewed.1This acceptably addresses the issue.
- 2. Contacts with other vendors p
L cThe licensee's position still remains that their intent is to fully comply before startup with l
the guidance in GL 90-03. The licensee has issued and implemented an improved L
procedure for the control of vendor information, DC 16, Vendor Equipment Technical -
f Information Program (VETIP), with Changes 1 & 2. This procedure describes an upgrade process in Section 1.7 called interim Recovery of Key Safety Related Vendor Technical Manuals. The inspector reviewed various aspects of tne process and noted that it l~
> appeared to effective and that the upgraded manuals baing produced were of high quality.
The licensee also submitted a revised commitment letter relative to vendor technical information to the NRC, letter B16912, dated 1/30/98. This letter states that all vendor
manuals for equipment on the Key Safety Related Equipment List (KSREL)'will be upgraded, and all associated procedure reviews will be completed before Unit 3 restart. It also states
- that when the 1998 vendor re-contact activities are complete, it is their intent to revise the L._
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vendor re-contact schedule from annual to tri-annual. The licensee has implemented a contract with PRC/ USA (part of a Centralized Vendor Re-contact Program) to perform and enhance their vendor contacts.
The following issues were noted from IR 97-203. The resolution of these issues is also included below.
The licensee had committed to annual vendor contacts in their response to GL 90-03,
but stated that they had plans to change this to once per three years.
The licensee has completed vendor re-contacts in late 1997 and 1998 as part of their vendor manual upgrade program in accordance with procedure DC-16. As noted above, the licensee has formally changed their commitment to the NRC to a tri-annual re-contact in letter B16912. This change is to be effective after the 1998 re-contact activities are complete.
Procurement Engineering Group (PEG) 6.05, Step 6.1 specified the minimurn items to
be included on the KSREL: however it left off four items from the GL, namely batteries, battery chargers, inverters, and cooling water pumps.
The licensee has revised and issued a controlled Unit 3 KSREL that addresses all items from the GL recommendation. This list was developed and issued per the new procedure DC 16. During NRC reviews of the KSREL, a few additional items were noted as missing (e.g., the RSS pumps). The licensee issued Rev.1, dated 3/3/98, to the KSREL to address this concern. This concern is acceptably addressed for Unit 3.
At the completion of the 1996 vendor contact cycle, PEG noted that, despite repeated
attempts, sor'ne of the vendors had failed to respond to requests for information.
j As part of the vendor manual upgrade program, the Department of Programs and Engineering Standards (PES), with the assistance of PRC/ USA, has contacted and addressed all required vendors for equipment on the KSREL.
The licensee performed a validation of a sample of vendor manuals (38 manuals were
validated) for Unit 3 in 1996 and 97. However, not all of the manuals for equipment on the Unit 3 KSREL (or for equipment types listed in the GL as key safety-related equipment) were validated.
. Subsequently, the licensee implemented the DC 16 vendor manual upgrade program that addressed all of the vendor manuals for the KSREL.
DC 16, Vendor Equipment TechnicalInformation Program, addresses receipt and
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control of vendor information and vendor manuals. The inspector reviewed various aspects of DC 16 implementation and noted no problems. However, as of the end of j
the inspection period, the last portion of the process, namely the review and updating of procedures to address vendor manual changes, had not yet been completed for all manuals on the KSREL. This aspect of the program remains to be reviewed. The l
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appropriate incorporation of vendor information into the procedures for the reactor trip breakers will be reviewed at the same time.
3. Internal hr.rdlina of onsite vendor services Acceptably reviewed in IR 97-203.
4. Other INPO 84-010 activities in January of 1997,INPO began the transition from NPRDS to a new system called Equipment Performance and Information Exchange (EPIX), and stopped accepting input into NPRDS. The licensee maintained the 1997 equipment failure information onsite and has recently batched it to INPO for input into EPIX. The licensee has established an EPIX coordinator. Implementation of industry access to EPIX data is scheduled for June,1998.
This is acceptable.
5. Summarv
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The various aspects of the vendor interface program, as outlined in NRC Generic Letter 90-03 and the lice isee's procedure DC 16, have been satisfactorily reviewed with the exception of the final review and updating of procedures to address vendor manual changes made during the vendor manual update process. This aspect of the program upgrade 'ned not yet been completed by the licensee by the end of the inspection periud.
SIL ltem 18 is hereby updated.
M8.2 Follow-up Corrective Actions for ACR M3-96-0685, Thermal Relief Valve Setooints a. Inspection Scooe (40500. 92903)
The Reactor Plant Component Cooling System (CCP) Thermal Relief Valve pressure settings were not in agreement with the piping design pressures shown on the Line Designation Tables (LDT). The purpose of the thermal relief valve in each system is to provide a pressure relief mechanism. The thermal relief valves prevent over stressing the CCP system by opening at design pressure should a portion of the system be valved shut and continue to receive heat, causing the fluid to expand. The original vendor-supplied pressure calculations failed to account for the elevation differences of system components.
The CCP system contains both ASME Class 3 and ANSI B31.1 (NU Class 4) piping.
b. Observations and Findinas The inspector previously reviewed ACR M3-96-0685 " Thermal Relief Valve Setpoints"in NRC Inspection Report 423/98-206. The resetting of the setpoints of the thermal relief valves, to take into account the static head caused by elevation differences in the system, is deemed adequate. The hydrostatic test of the three lines with a design temperature above 200 degrees F has been satisfactorily completed. The previous construction hydrostatic testing is deemed adequate for the other lines with a design temperature below 200 degrees F.
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c. Conclusions The corrsctive actions implemented by the licensee in response to ACR M3-96-0685 were found to be appropriate and no further inspection of this issue is deemed necessary.
' M8.3 iClosed) IFl 423/97-01-07. Follow-uo of Seismic 11/1 Corrective Action a. IDsoection Scope (92902)
CR M3-98-0339 was issued to address a deficiency in the strength criteria for the restraint of temporary equipment, provided in Millstone Station housekeeping and maintenance Standard OA 8. The inspector reviewed the revision to Station Procedure OA 8, and its
. basis, implememed to correct the deficiency.
b.L Observations and Findinas Millstone station housekeeping and maintenance Standard OA 8 provides guidelines for the restraint of temporary equipment within the site. Included in the guidelines is the
. specification of a load design criteria for the restraint devices. This strength criteria was
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identified as deficient for Unit 3, during the NRC inspector's review of licensee controls and procedures for temporary equipment (IFl 423/97-01-07). Specifically the standard required that the restraint devices be capable of resisting 70% of the secured item weight.
. The 70% criteria, although appropriate for Unit 2, did not envelope the peak horizontal seismic acceleration to be expected for any rigid equipment in Unit 3. The licensee issued CR M3-98-0339to address this concern. IFl 423/97-01-07temained open pending resolution of this ' issue.
As corrective actions, the licensee reviewed the seismic design criteria for Unit 3 and revised the strength criteria specified in the standard accordingly. A strength criteria of-100% was determined to be appropriate.
The inspector reviewed the revision to'OA 8 and its basis. Change 2, Revision 2, of OA 8 shows the revised strength of.100% of secured weight as the strength criteria for the restraint of temporary equipment. To support this criteria the licensee included in the CR closure package a tabular listing of ZPA values (rigid body accelerations) for all elevations of all Unit 3 structures for both the % SSE and SSE seismic events. The 100% value was seen to envelope the ZPA at all locations.' For all locations, except the highest elevation in the containment external structure, the 100% value exceeded the ZPAs by at least 20%.
- c. Conclusions.
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a The revision to the Millstone Station housekeeping and maintenance Standard OA 8 is considered appropriate and supported with an acceptable basis. The strength criteria issue
. is resolved, the disposition of CR M3-98-0339is considered acceptable, and inspector follow-up item IFl 423/97-01 F? is closed.
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U3.Ill Enoineerina U3 E1 Conduct of Engineering
,E1.1 Reactor Plant Component Coolina (CCP) Svstem Ooeration above Desian
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. Temperature and Other Failure Modes (Closed - SIL ltem 13)
Previous inspections were conducted of the technical issues involved with SIL ltem 13 and were. documented in inspection reports 50-423/96-08,97-203, and 98-206. During this
. inspection, licensee corrective actions were essentially completed and verified to be,
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l adequate, as documented in the following sections. SIL ltem 13 is hereby closed.
E1.1.1; iC1gjed) eel-423/96-201-22:(Closed) URI 96-08 20:(Closed) ACR M3-96-0326:
and (Closed) ACR 13427: RHR Flow Control System Failures and CCP
. Overheating a. Inspection Scone (92903)
< The above issues were previously reviewed in NRC inspection report 423/98-206. As identified in eel-423/96-201-22,the Reactor Plant Component Cooling Water (CCP) system
. upper temperature limit of 115*F was exceeded on September 9,'1994 and April 15, 1995. This item was subsequently updated by URI 50-423/96-08-20. The NRC has also
- issued a Notice of Violation and Proposed imposition of Civil Penalties by letter dated
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December 10,1997 that includes this item with NOV letter unique identifier 04033. The actions with respect to this letter will be separately reviewed.
On August 19,1996,in'LER 96-013-01,the licensee reported 'a design deficiency in the Residual Heat Removal System (RHS) that was outside the design basis of the plant. A l
loss of control' air could cause the RHS control valves 3RHS*HCV606 and/or 3RHS*HCV607 to fail open. If this. condition occurred during the initial phase of a plant cooldown, the CCP temperatures could rise above the 125*F used in the system stress
' analysis. This item was updated in,NRC Inspection Report 50-423/97-203,Section 04.1,
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l regarding modifications completed on the RHS Train "A" to allow RHS to continue a normal
- cooldown or safety grade cold shutdown upon loss of instrument air without exceeding CCP piping design temperature limits. The modification of the Train "A" RHS control
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g valves (i.e.,3RHS*HCV606)was considered to be closed.
l During the current inspection, the inspector continued to review the licensee's design l
' engineering activities to resolve the technical concerns associated with this issue and
. assessed the adequacy of the resultant changes to plant operating procedures.
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b. ' Observations and Findinas
DCR M3 96065, ~3RHS*HCV 606,607 Failure and Adverse Effect on CCP Piping," Rev.
i 0,7/2/97, was prepared in response to ACR 13427.' The ACR documented that, upon a-l loss of nonsafety-related instrument air to RHS flow control valves 3RHS*HCV606 and
607 (while in Safety Grade Cold Shutdown (SGCS) or during normal cooldown), the control i
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p
- valves will fail open and the CCP return temperature from the RHS heat exchanger may Lincrease above the maximum operating' temperature of 115'F.
Previously, regarding'the RHRS Train "B" modification, the licensee issued an engineering release form (DCM Form i dated 09/04/97) for the Train B affected components restricting the plant to Modes 5 and 6 pending completion of DCRs M3 96075, M3 97015, and M3 96064.
During this inspection, the licensee provided documentation that the RHS Train "B" modification had been completed and that the system was released to operations on 3/23/98.
In the previous inspection, the inspector reviewed several calculations by a licensee consultant, Proto-Power, that were referenced in DCR M3 96065, which identified the revised operating temperatures of the RHS and CCP systems. The inspector found the-calculations to be complete and comprehensive with the exception of Proto-Power Calculation 96-011, Paragraph 6.08, for the RHS Pump Seal Coolers, RHS*E2 A or B. In particular, the justification for the acceptability of the RHS pump seals, which are cooled by the CCP system, when subjected to a revised, increased CCP temperature of 113*F
' during SGCS, was questioned. The manufacturer strongly recommended that the pumps -
be operated with an adequate supply of cooling water to the seal coolers, i.e., 5 to 10
. GPM to the shell side of the cooler, and further stated that lack of coolant will greatly increase the temperature of the mechanical seal unit, resulting in shorter seal life. The -
inspector questioned whether seal failure might occur during the length of time assumed for SGCS and normal shutdown, as per Proto-Power Calculation 95-052 references of 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> and 124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br />. This 'was identified as an open item, pending confirmatory
' documentation from the seal manufacturer.
During this inspection, the licensee provided a memorandum dated 1/27/98 (CBM 98-012)
of a phone conversation between the licensee's condition based monitoring pump specialist and the seal manufacturer in which the manufacturer was quoted as saying that if the CCP cooling water temperature increased from 95'F to 115'F, the maximum temperature which the seal would experience would be'180*F. The seal design has a normal operating L
. seal cavity temperature limit of 2OO'F. The RHS pump seals can remain operable at
. temperatures above 2OO*F, up to a maximum of 350*F, but with increased wear rates.
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LThe inspector considered this response to satisfactorily address the open item described above.
in the previous inspection, the inspector also reviewed the operating procedures affected
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by the changes identified in DCR M3 96065 pertaining to the RHS and CCP interface and
- the modifications ~made to the RHS system. Several procedures did not yet identify or Linclude any changes related to DCR M3 96065. Therefore, the issue of completion of changes to operating procedures was identified as an open item.
. During this inspection, the inspector requested verification that operating procedures of the
- CCS system for normal plant operation had been changed as required in response to the poti cui CCP overheating concerns. In response, the licensee identified another DCR M39tG6, entitled "QA Upgrade for 3CCP*TV32A, B, & C Pneumatic Controls." This
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DCR was intended to upgrade the non-safety grade pneumatic controls of temperature control valves 3CCP*TV32A, B, & C. The controls for the valves were upgraded to safety related components. As a result, loss of instrument air could now be assumed to affect only one train of CCP. Therefore, normal plant operation could continue under a technical specification limiting condition of operation. The licensee provided documentation that DCR M3 96086 was completed as of 1/20/98.
J For DCR M3 96086, the licensee issued OP 3330A, " Reactor Plant Component Cooling Water," Rev.14, Change 1,12/22/97; OP 3330A-2, " Reactor Plant Component Cooling (Common)," Rev. 5, Change 1,12/22/97; and OP 3330A-3," Reactor Plant Component Cooling (Train A)," Rev. 8, Change 3,12/22/97. Therefore, all procedural changes related to DCR M3 96065 were actually issued under DCR M3 96086. The inspector considered
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the issuance of these procedural revisions as addressing the concerns for potential CCP
!
overheating and closes the open item previously described.
During this inspection period, the licensee also issued DCR M3 96064, " Safety Grade Cold Shutdown Analysis - DWST Inventory, CCP Temperature Limitations and Spent Fuel Pool Cooling," Rev. O,3/28/98. This DCR implemented a new SGCS analysis based on
increased CCP and service water (SW) allowable upset operating temperatures that were implemented under DCRs M396065, M3-96075, and M3-97015. The licensee also issued OP3208, " Plant Cooldown," Revision 18, Change 3, 3/15/98, which identified changes made to the procedure to address the high temperature limitations for the RHS heat
. exchanger outlet temperature on the CCP side and for the CCP heat exchanger on the CCP side. All of the CCP piping had been certified as acceptable for the low service water conditions without operating restrictions.
The licensee indicated that all af the supporting stress analysis calculations for DCRs M3 96075,"CCP System Design %nperature and Support Modifications," Rev.'2,2/24/97, and M3 97015, "CCP Supply and Return Piping Temperature Reevaluation," Rev. O, 8/1/97, had been completed by the architect engineer (Stone & Webster in Boston) and that the owner's review had been conducted at the architect engineer's offices.
Documentation that DCR M3 96075 and M3 97015 had been completed was presented.
c. Conclusions In this inspection, the licensee presented documentation that DCRs M3 96064, M3 96065, M3 96075, and M3 97015 had been satisfactorily completed, including necessary stress analyses, and that related operating procedures had been issued. The licensee also provided confirmatory documentation from the RHS pump seal manufacturer that the seals can withstand temperatures up to 200*F. Therefore, eel-423/96-201-22and URI 96-08-20 are technically closed, as are the related licensee condition reports, CR M3 96-0326 and ACR 13427. The NRC Notice of Violation (NOV -letter unique identifier 04033)
currently remains administratively open.
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E1.1.2 (Closed) LER M3-96-028-OO and 01: Overcooling of CCE Charoina Pumo Lube Oil System Due to Loss of Instrument Air Concurrent with Low Service Water Temperature a. Insoection Scone (92700)
' These LERs were previously reviewed in inspection report 423/98-206. In LER 96-028-00, f
"the licensee reported that a loss of instrument air to the temperature control valves (3CCE*TV37A and B) in the CCP system serving the charging pump lube oil coolers (CCE),
coincident wity 33*F service water (SW) temperature, could result in ~an overcooling of both trains of the charging pump lube oil system and challenge charging pump operability.
.On December 13,1996,in supplemental LER 96-028-01,the licensee reported the cause of the potential charging pump inoperability to be inadequate initial design. Overcooling of
- the lube oil system below the minimum allowable temperature of 60*F could occur following a failure of the non-QA instrument air system (IAS) coincident with worst case minimum SW inlet temperature to the lube oil coolers and maximum flow and maximum lube oil cooler cleanliness. - The air-operated CCE valves would fail open and excessive i.
. cooling of the lube oil system down to 40*F would occur. During this current inspection,
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the inspector reviewed the licensee's engineering activities to resolve the technical concerns associated with this issue and assessed ongoing plant design modification activities. The inspector also reviewed activities concerning a similar issue for the safety injection pumps (3SlH*P1 A and B) and the safety injection pump cooling system (CCl).
b, Observations and Findinas -
During the previous inspection, to qualify the charging pumps for operability with lube oil
' temperature of _40*F, the licensee issued Design Change Notice (DCN) DM3-OO-1466-97,
" Revise Cooling Water Temperature' and Lube Oil Pressure for Charging Pumps," 10/14/97, to change the normal oil supply pressure from 15-18 psig to 20-24 psig to compensate for the higher lube oil viscosity at the lower temperature.
During the current inspection, the inspector noted that the licensee had subsequently issued DCR M3-98015,"3CCE 'TV37A/B Travel Limiters to Prevent Cooldown." This
. DCR was issued to correct problems of excessive lube oil leakage from the bearing seals of l
the charging pumps that occurred when the lube oil pressure had been raised to 20 to 24
- psig.. It reestablished the lube oil pressure at the original 15 to 18 psig level based on a
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reanalysis of the CCE system to take into account that upon loss of instrument air, the air-l operated CCE pump suction cross-tie valves 3CCE* AOV26A/B and pump discharge valves
3CCE*AOV30A/B fail closed. For this scenario, the trains of CCE pumps are separated, j
unlike normal plant operation. The DCR specified the installation of travellimiters on temperature control valves 3CCE*TV37A/B. By mechanically limiting the opening of the temperature valves upon loss of instrument air, the licensee then determined the CCE flows required for 33*F service water to maintain a lube ' oil temperature of 55*F.
By means of Calculation No. 3-92-103-191M3, Revision 1, "CCP-CHS Pump Area Ventilation," Change 6,3/5/98 and Change 7,3/28/98,the licensee had determined that l
uthe ambient temperature'in the cubicle of a standby charging pum'p during a loss of offsite l
power, with no single failure, will be approximately 55*F while the temperature in the j
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cubicle of the operating pump will be about 65*F. These temperatures are maintained by eight 30 kw heaters, four on each of the two emergency buses. In the event of a loss of offsite power, the previously operating charging pump will be sequenced to restart while the standby pump will remain idle. However, the heaters for the standby pump cubicle will continue to be powered by the emergency diesel generator supplying the standby pump.
Tnerefore, no single failure will allow temperature to drop below 55*F,if the standby pump is required to operate. Failure of the bank of heaters for the standby pump cubicle would already constitute the single postulated failure, thereby eliminating the requirement for the standby pump to be. operable.
In a June 2,1994 letter to the NRC, the licensee revised the definition of charging pump operability in the technical specifications, to indicate that permanent heaters had been installed to maintain a temperature of at least 32'F within the charging pump /CCP pump areas of the Auxiliary Building. By NRC letter of January 3,1995,in Amendment No.100 to the Facility Operating License, the NRC accepted the revised definition of charging pump i
operability to eliminate reference to the temporary heaters.
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This 55'F ambient air temperature was assumed in Westinghouse calculation P-EC-276, l
Rev.1, "CH/SI Pump Operation with Cold Ambient Conditions." The calculation states j
that prior to pump startup in the standby Mode, fluid within the pump may be at i
equilibrium with the ambient, approximately 55'F, and that the solubility of boric acid at that temperature is about 3.75 Wt. %, or 6500 PPM boron. It further states that in the -
event that the boron concentration of the static fluid exceeds 6500 PPM during the standby Mode, any boron crystals would likely settle in the seal cavity. Upon pump startup, the seal will be continuously flushed with the " clean" process fluid and the boron particulate will be quickly removed and no significant seal damage is expected for this condition.
The licensee assumed that the lube oil would reach a minimum temperature of 33'F.
According to a March 4,1998 letter from Westinghouse, the lube oil has a pour point of 21 *F, and the pump manufacturer's guidelines are that the oil have a pour point at least 10'F below the minimum. Westinghouse therefore concluded that the standby charging
!
pump can be started even without having first operated the auxiliary lube oil pump.
In the previous inspection, the inspector questioned how the licensee could achieve SGCS
' within 66 hours7.638889e-4 days <br />0.0183 hours <br />1.09127e-4 weeks <br />2.5113e-5 months <br /> assuming a loss of offsite power and a single active failure such as loss of one diesel generator or one bank of charging pump cubicle heaters if the area temperature drops below 59"F. This was incorporated into URI 423/96-08-20. In view of the additional information provided by the licensee with respect to charging pump operability at
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low service water temperatures, that portion of the unresolved item is considered closed.
i The licensee had incorporated appropriate changes in operating procedures OP 3304A,
" Charging and Letdown," Rev. 26, Change 6, OP 3353.MB3A," Main Board 3A (.
Annunciator Response," Rev.1, Change 4, and OP 3353.MB38," Main Board 3B
Annunciator Response," Rev. 4, Change 6 to address low temperature operation of the
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l charging pumps, including condition monitoring of the lube oil.
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in the previous inspection, in a related issue, the licensee provided minor modification (MMOD) M3-97605, Rev. O,10/15/97," Safety injection Pump Cooling System (CCl) Low Temperature Design." This MMOD lowered the CCI minimum design temperature, originally specified in vendor documents as 60oF, to 40'F. ACR M3-96-0218 teported a lack of design documentation supporting operation of the Safety injection Pumps (3SlH'P1 A and B) under a SW temperature condition of 33*F. The ACR corrective action required analysis and production of design documentation to assure SI pump operability under this condition. This issue was self identified in ACR M3-96-0218,"CCl Overcooling," 6/23/96, but the operability of the Si pumps under this condition was not confirmed until April,1997 upon completion of a study by the pump rnanufacturer, Ingersoll Dresser Pump Co., dated 4/01/97. The written analysis by the pump manufacturer did not provide a complete description of the method of analysis. The licensee subsequently obtained a letter from the manufacturer dated 2/5/98 which indicated that the manufacturer had reviewed documentation by the licensee of phone conversations describing the method of analysis used by the manufacturer and that the manufacturer was in general agreement.
I During this inspection, the inspector reviewed the record of phone conversations describing the method of analysis in detail. The inspector concluded that the safety injection pumps had been properly certified for operability with 33*F lube oil temperature and that this issue concerning the potential deportability of the safety injection pumps was closed.
c. Conclusions The three issues identified in the previous inspection, 423/98-206,were closed during this inspection, as follows:
1. Required changes in operational procedures were made as a result of the new design modification. DCR M3 98015 concerning installation of travel limiters on valves of the charging pump lube oil set pressure; 2. The licensee's operability determination for the charging pumps under low service
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water temperature of 33'F as initially presented was incomplete and there were discrepancies in the analysis concerning the ambient temperature in the charging pump cubicles. This issue was incorporated into unresolved item URI 96-08-20. In view of I
the additional information provided by the licensee with respect to charging pump operabill' / at low service water temperatures, and based on the revised approach of installing travel limiters on the CCE temperature control valves, this issue is now resolved; and 3. For the safety injection pumps, the description of the method of analysis by the pump manufacturer was initially incomplete. During this inspection, based on additional information concerning the method of analysis, the inspector concluded that the safety injection pumps had been properly certified for operability with 33*F lube oil temperature and that this issue concerning the potential deportability of the safety injection pumps was closed.
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- LERs 96-028-00 and 01 are considered closed.
L E1.1.3 (Closed) LER 96-040-00 and (Closed) ACR M3-96-0887: Potential Component
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Coolina System Overcooling Due to Loss of Instrument Air System Concurrent with Low Service Water Temperature a. ' Inspection Scooe (37551. 92700)
l in accordance with 10 CFR 50.73, on November 22,1996,in LER 96-040-00,the licensee
' reported a failure scenario in which a loss of the nonsafety-related (NSR) Instrument Air System (IAS) would allow Reactor Plant Component Cooling Water (CCP) system heat i
exchanger outlet temperature control valves (3CCP'TV32A/B/C) to reposition to maximum l
cooling configuration. Coupled with a low heat load and minimum Service Water (SWP)
inlet temperature, the CCP system could reach temperatures lower than values for which they are analyzed, thereby rendering the CCP system, and systems that it serves, potentially inoperable.- The licensee reported the causes of this event to be: (1) improper initial design of the CCP system wherein the plant's architect engineer did not analyze for
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extremely low CCP heat loads concurrent with very low SWP temperatures; and (2)
inadequate review of industry and Millstone 3 operating experience evaluations associated <
with the CCP system and loss of the IA system. During this inspection, the inspector -
reviewed the licensee's engineering activities to resolve the technical concerns associated with this issue and assessed ongoing plant design modification activities, b. Observations and Findinas The inspector continued the review of the licensee's engineering activities, which included l corrective actions taken under ACR M3-96-0887.. The corrective actions were: temporary and permanent modifications to the three-way CCP heat exchanger tem'perature control valves 3CCP*TV32A/B/C; review and update of.CCP stress data packages; changes to operating procedure OP3353.MB1C;and training.
' Previously, the' inspector reviewed DCR M3 97015, Ref. 3.28, Proto-Power Calculation 97-129, Rev. A, "CCP Heat Exchanger Process Temperature Results From 33*F CCP Temperature Operations," dated 2/3/98. The conclusions of the calculation were that
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failure of the CCP_ temperature control valves together with a 33*F CCP temperature will result in a process side ~ outlet temperature of 54*F from the RHR Heat Exchangers, 52.5'F from the Spent Fuel Pool Heat Exchangers, and 40*F from the Seal Water Heat Exchangers, it was recommended that the RHR stress data package calculation SDP-RHS-01360M3, Rev (9), Spent Fuel Pool stress data package calculation SDP-SFC-01363M3, Rev (4), and the Charging System stress data package calculation SDP-CHS-01336M3, Rev (12) all be updated. In Attachment D, the licensee enclosed lette'r 25212-ER-98-0026, dated 1/30/98, to Proto-Power which included design inputs for the calculation to
? determine the effects of cooling the RHR heat exchangers (3RHS*E1 A/B), Spent Fuel Pool Heat Ex' changer'(3SFC*E1 A/B), Letdown Heat Exchanger (3CHS*E2), Excess Letdown I
Heat Exchanger (3CHS*E1 A/B) and Seal Water Heat Exchanger (3CHS*E4) with 33*F cooling' water resulting from a failure of the CCP temperature control valves (3CCP*TV-32A/B/C).
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- During the current inspection, the licensee presented a memorandum, MP3 DE 98-OO65, dated 2/12/98, which indicated that the design inputs for this calculation had been verified for the calculation that was accepted on 2/7/98.-The licensee stated that'the calculation
, had been installation v'erified and therefore was closed.
In the previous inspection, the inspector performed a sample walkdown of piping support modifications in the Auxiliary Building and the Fuel Building pertaining to DCR 97015. To the extent that field verification was possible, all modifications were completed as shown
- on the drawings. The licensee indicated that all of the support modifications had been
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completed except three for the CCP system and one for the SW system, in the current inspection, the licensee presented documentation that all of the modifications had been completed on 12/22/97. Therefore, DCR M3 97015 was considered closed and released for operations. Changes to plant operating procedures were determined not to be required for the support modifications performed under DCR M3 97015. The licensee also issued DCR M3 96064," Safety Grade Cold Shutdown Analysis
- DWST Inventory, CCP Temperature Limitations and Spent Fuel Pool Cooling." This DCR implemented a new SGCS analysis based on increased reactor plant component cooling
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water (CCP) and SWP allowable upset operating temperatures that were implemented under DCRs M396065, M3-96075, and M3-97015.
In view of licensee review and approval of the stress analysis calculations, completion of the support modifications, and determination that no operating procedural changes are
_ required, LER 96-040-00 and ACR M3 96-0887 are considered closed,
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c. Conclusions The licensee reviewed and app' roved the final stress analysis calculations, complete'd the,
required support modifications, and determined that no operating procedural changes are
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required. These actions satisfactorily resolved issues concerning potential component cooling system (CCP) overcooling due to loss of instrument air concurrent with low (33*F)
service water temperature. LER 96-040-00 and the related ACR M3 96-0887 are closed.
I U3 E2 Engineering Support of Facilities and Equipment E2.1 -
Recirculation Sorav Svstem Review and Corrective Action Followuo As documented in inspection report 50-423/96-04,the licensee first notified the NRC on April 3,1996, of design-basis problems involving the recirculation spray system (RSS).
Since that time, additional RSS design problems have been identified and reported.
Significant NRC inspection resources have been expended in the review and followup of RSS issues, collectively summarized in significant item list (SIL) items 1 and 85. Other inspection reports documenting the review of the RSS design and required corrective
_ actions include 50-423/96-06,97-202,97-203,97-206,97-209, and 97-210.
l During this inspection, the NRC Office of Nuclear Reactor Regulation (NRR) completed its j
review of the licensee's engineering and licensing documents to evaluate the approach i
'taken to resolve the RSS problems that have been identified. The NRR assessment is t-l
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documented in the following section and addresses the concerns and issues related to SIL ltems 1 and 85. It is noted, however, that a licensee-identified unreviewed safety question
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associated with a modification made in 1986 to eliminate direct RSS injection into the reactor coolant system is still under review as part of the licensee's related license amendment application.
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Also during this inspection, supplement 1 to LER 97-028 was reviewed relative to the proposed modifications to correct the historical problems with the RSS design. As a result
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of,this reviewfin conjunction with the NRR assessment, LER 97-028-011s considered
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closed. The inspector also reviewed corrective actions for LER 96-39-00,affecting RSS i
operability, as' discussed below.
As a result of damage to expansion joints in the RSS pump discharge piping identified during post-modification testing of the RSS design change implementation in March 1998, the licensee established a multi-discipline review team to assess and manage the design i
evaluation, clean-up, restoration, and re-tests of the RSS. The NRC issued a meeting record on April 16,1998, to document discussions between the NRC and both the licensee and the ICAVP contractor on the final resolution of the RSS design intended to address the cavitation identified as the root cause of the expansion joint failures. Further NRC inspection was conducted to review the licensee's technical evaluation to find and retrieve the missing shield pieces from the damaged expansion joints. Additional questions were
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raised regarding stress calculations and ASME Code compliance for the RSS pump and piping components, as such data supported the licensee's final design modifications and corrective action for the cavitation problems. The NRC inspection and assessment of the
. engineering approach taken by the licensee to resolve the identified problems is.
.. documented below.
Finally, the inspector coriducted a field walkdown of the completed RSS piping and component modifications, evaluating the design change record revision details and in-plant system and component conditions. As discussed below, licensee evaluations, final
- modifications, and corrective actions to address the multifarious problems with the original RSS design and subsequent design change problems appear to be appropriate, as verified by the implementation of final system testing and the acceptable test results.
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E2.1.1 (Closed) Eels 50-423/96-06-13and 97-202-09 Recirculation Sorav System (RSSI Deficiencies (Closed - SIL ltems 1 & 85)
a. Inspection Scope (37550)
. On April 3,1996, the licensee determined that the plant had operated in a condition that was outside the design basis due to a deficiency in the design of the recirculation spray system (RSS) piping supports, for which the loading analysis had not appropriately considered accident temperatures. Subsequently, the licensee determined that based upon
- design basis accident temperatures inside containment, the unacceptable pipe support
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stress conditions also applied to the quench spray system (OSS). In NRC Inspection Report (IR) 50-423/96-06,the staff determined that this design deficiency was an apparent violation (eel 50-423/96-06-13)of regulatory requirements.
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-78 On January 13,1997, a licensee engineering evaluation determined that the RSS heat exchangers and piping may be susceptible to water column separation, and subsequent water hammer events,'if the RSS pumps are restarted during design basis accident conditions. On February 4,1997, a licensee review of design calculations identified that the calculated minimum water levelin the containment sump at the time of the start of the RSS pumps following a large break loss-of-coolant accident (LOCA) would be below the containment sump vortex suppression gratings. It was determined that cavitation of the operating RSS pumps could result from the air entrainment which would accompany the postulated vortex formation in the sump coolant. On April 10,1997, another review of the design calculations for the net positive suction head (NPSH) for the RSS pumps identified the potential for steam flashing and partial voiding of the coolant from the containment sump based upon suction line head losses in excess of the calculated availability of
. saturated coolant head conditions. - In NRC Inspection Report 50-423/97-202,the staff determined that these design deficiencies represent an additional apparent violation-(eel 50-423/97-202-09)of regulatory requirements.
Based on the initial staff review of the licensee's modifications and procedural changes to
. address the above issues, a request for additional information (RAl) was issued on February i
- 3,1998. In the RAl, the staff stated that based on a limited review, it appeared that a design change in 1986, which was done under the provisions of 10 CFR 50.59, may not
- have adequately addressed the three questions of 10 CFR 50.59. Further, the staff
- requested specific information concerning the modifications performed on the RSS during the current outage.
By letter dated February 16,1998, the licensee addressed the staff's questions. The questions and an overall presentation of the RSS were further discussed during a public meeting on February 19,'1998. In the February 16,1998, letter, the licensee stated that an integrated safety analysis was performed on the RSS u' sing the original Millstone Unit 3 -
Safety Evaluation Report (NUREG-1031) as the basis. The integrated safety analysis
- identified ac unreviewed safety question (USQ) associated with the modification made in 1986 which eliminated direct injection to the reactor coolant system. This issue is being
. addressed separately by the NRC and will be documented in the staff's response to the licensee's license amendment application dated March 3,1998. The licensee concluded that the remaining modifications, which were done under the provisions of 10 CFR 50.59, were adequate.. During this inspection period, the staff reviewed the licensee's February 16,
.1998, response and the integrated safety analysis for the RSS.
b. Observations and Findinas During the current outage, the licensee made several modifications to the RSS under the provisions of 10 CFR 50.59. In each of the cases, the licensee determined that the change was not a USQ. The more significant changes included (1) rerating and reanalyzing of RSS piping and pipe supports (this included modifications to some of the pipe supports); (2)
- installation of restricting orifices on the discharge of each RSS pump, (3) capping 50 percent of the RSS containment spray nozzles, (4) lowering of the vortex suppression grating in the containment sump by 12 inches,'(5) changing the normal position of the RSS pump mini-flow recirculation va!ves from open to closed and installing an interlock for valve opening logic, (6) installing flow test loops around RSS pumps C and D, and (7) changing the l
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operator action time for completing the switchover of the emergency core cooling system
.(ECCS) from the injection mode to the cold leg recirculation mode from 10 minutes to 25 minutes, in addition, during the ECCS recirculation modes of operation, the system
. alignment has been changed to allow all four RSS pumps to supply water to the RSS -
containment spray header while maintaining only two pumps for the ECCS function.
RSS Pioina and Pine Sunoorts L
. In IR 50-423/97-203,the staff reviewed documents of record for a portion of Train B of the RSS to confirm that the licensee had revised the original design documents or prepared new documents to address the deficiency in the design of the RSS piping and pipe
. supports. The staff stated that during the inspection, no substantial design or performance concerns were identified.- in the letter dated February 16,1998, the licensee provided a summary of the reanalysis that was performed on the RSS piping and pipe supports and described the modifications that were required. The licensee further stated that the modifications and reanalysis were determined not to be a USQ. The staff had no further questions in this area.
Installation of Restricting Orifices and Caocina Sorav Nczzles in 1985, the NRC evaluated the containment heat removal systems. The evaluation
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containment peak pressure below 36.1 psig, reducing the containment pressure to subatmospheric pressure in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, and maintaining the containment pressure to less than atmospheric for 30 days. The Millstone Unit 3 containment design pressure is 45 ~
psig.
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In 1991, the licensee submitted an amendment request that was approved by the staff to change the containment functional design from subatmospheric to that of a large dry containment. The licensee submitted analyses that showed that the'QSS along with the RSS were capable of maintaining the containment peak pressure below 38.6 psig and reducing the containment pressure'to half of the peak at 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> into the accident and maintaining the pressure to less than half the peak 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the initiation of the
.. accident. The staff found these analyses acceptable because the licensee used the same methods and computer models as those used in the previously approved analyses. These functional requirements were assumed in the licensee's 10 CFR Part 100 dose calculations
'
.and form part of the current licensing basis for the QSS and RSS.
~ In 1997, the potential for flashing in the RSS suction line and waterhammer in the pump discharge piping were identified as concerns.- In response to these concerns, the licensee modified the system, under 10 CFR 50.59, by installing restriction orifices on the discharge.
of each RSS pump. Because flow to the RSS spray headers is reduced by the RSS pump restriction orifices, 50 percent of the RSS spray nozzles were plugged in order to maintain adequate pressure drop across the spray nozzles. The licensee believed this was acceptable, under 10 CFR 50.59, because its revised peak pressure analyses were
. bounded by the 1991 peak' pressure curve. These revised analyses contained many new assumptions, such as a new debris transport model, crediting excess flow from the other
'RSS pump in the operating train, and using a different computer model (LOCTIC Version
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23, Level 3 instead of Level 2). The staff questioned whether the RSS changes had been i
adequately assessed and whether the system design changes were compensated for by changing the input assumptions and using a different version of the code. The licensee performed a rebaselining study to address the staff's concern. As a result of the study, it was determined that the actual LOCTIC version used in the 1985 analyses was LOCTIC Version 23, Level 01. The Level 02 model was used in the analyses supporting the 1991 Technical Specification change.
The RSS is modeled with multiple paths by LOCTIC Version 23, Level 03, as opposed to a single flow path by Level 02. The licensee stated that any difference in the calculations is solely due to round off errors and that no change was observed in the containment pmssure results. The difference between LOCTIC Version 23, Levels 02 and 01 was how hot spray was modeled. When spray water was hotter than the containment atmosphere, Level 01 only considered sensible heat transfer from the droplet to the atmosphere but did not consider evaporation. In Level 02, spray water is permitted to evaporate into the atmosphere. This evaporation cools the spray water to the containment dew point
'
temperature. The rebaselining study showed that the temperature excursion that occurred when hot spray entered the atmosphere was significantly reduced when the Level 02 model was used. The licensee stated that the temperature excursion, which could occur in Level 01, was never encountered in any containment safety analysis for Millstone Unit 3.
Based on the summary of the rebaselining study, the staff concludes that the NRC's previous evaluations of containment pressure, as documented in NUREG-1031 and Amendment 59, have been preserved.
As far as the two other major changes in assumptions, the staff reviewed and approved the debris transport methodology as part of the originallicensing process for Millstone Unit 3. The licensee used the guidance of Regulatory Guide 1.82, Revision 1, in the development of its model.' Since that time the licensee has made changes to that model as i
permitted by 10 CFR 50.59. The staff has reviewed these changes and agrees that they i
could be made under 10 CFR 50.59. From a containment removal perspective, the staff I
does not believe that crediting excess flow from the other RSS pump is a USQ beceuse two of the four RSS pumps no longer need to be isolated from the spray header. All four pumps start approximately 11 minutes after accident initiation and are aligned to the spray header (issue further discussed below). The staff had no further questions in this area.
Vortex Sucoression. Mini-Flow Recirculation Valves. and Installation of Flow Test Loons in IR 50-423/97-210,the team reviewed the safety evaluations and analysis associated with (1) the lowering of the vortex suppression grating in the containment sump by 12 inches, (2) the change in the normal position of the RSS pump mini-flow recirculation valves from open to closed and installing an interlock for valve opening logic, and (3) the installation of flow test loops around RSS pumps C and D. Based on the review, the team had no further questions concerning the modifications.
In its letter dated February 16,1998, the licensee provided a summary of the three modifications. In each case, the licensee stated that the modifications were determined not to involve a USQ. The staff reviewed the licensee's submittal and had no further questions in this area.
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Ooerator Action Time for Comotetino Switchover A review of the Standard Review Plan, Chapter 15, Accident Analysis, indicates that operator actions for steam generator tube rupture, boron dilution, anticipated transient
,
without scram, and transients requiring manual tripping of reactor coolant pumps (RCPs)
I were credited as part of the design basis analyses. For both, a boron dilution event and steam system and feedwater system failures which require a RCP trip there are explicit i
limits on the timing of operator responses to cope with these transients.
I For other analyzed accidents, the NRC has not set specific time limitations on crediting operator action for mitigation of design basis events. In those instances where licensees consider temporary or permanent cnanges to the facility which credit operator actions for i
previously automatic system or component actuations, the staff has relied on the guidance provided in Generic Letter (GL) 91-18,"Information to Licensees Regarding Two NRC
'
inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and
on Operability," and ANSI /ANS 58.8, " Time Response Design Criteria for Safety Related Operator Actions," 1984 (ANSI-58.8), for evaluating such changes. Characterization of the guidance in the GL and ANSI-58.8, through detailed analysis including the use of the plant-specific simulator, provide a means for a licensee to assess the likelihood of
,
accomplishing the required actions and the consequences of delayed or missed
'
opportunities to complete such actions. The analyses should provide a licensee with
- insights to help determine if the proposed change constitutes a USQ.
The licensee submittal provided an operator action summary for the RSS that stated that the transition between the injection phase of a LOCA and the cold leg recirculation phase
.
requires manual operator action to realign the suction of the charging and intermediate head safety injection pumps from the reactor water storage taak (RWST) to the discharge i
of the RSS. Prior to 1998, the FSAR stated that the operators could complete this transfer'
within 10 minutes after receipt of the low level RWST alarm. This time was in the original plant design to ensure an adequate RWST inventory for quench spray operation and to meet the 1-hour subatmospheric requirement. This requirement was eliminated with the 1991 containment design basis change.
As a result of changes in valve stroke times in the command and control communication protocol in the control room, the time for operators to complete the transfer from injection phase to recirculation phase has increased. (Note that the training department collected simulator data from six operator crews between September and October 1996 revealing the average response time to be 15 minutes. Therefore, the licensee modified the FSAR to state that the switchover will be completed within 25 minutes) The licensee completed calculations, which demonstrate that sufficient RWST inventory is available to support ECCS pump operation for a minimum of 25 minutes after reaching the low-low RWST level.
During a March 6,1996, telephone call, the licensee stated that the only change from an operational standpoint was that the operators no longer have to close the two spray header isolation valves. All other actions, including the closing of two RSS direct injection -
isolation valves, when transferring to long-term cold-leg recirculation were consistent with past procedural guidance. The staff confirmed that the licensed operators were adequately trained on the revised procedures and methodology change associated with the swapover a ___ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _
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sequence, and were capable of performing the swapover actions well within the 25 minute i
timeframe. During the call, the licensee further stated that all of the operating crews
.i performed the actions within the timeframe required with the average time of I
'
approximately 15 minutes.
I in the February 16,1998, submittal, the licensee stated that the changes to Emergency -
j
. Operating Procedure (EOP) ES-1.3, " Transfer To Cold Leg Recirculation," were covered in significant depth in the classroom, including the basis behind each step. Additionally, each
~
operating and administrative crew performed the transfer to cold leg recirculation on the simulator twice. The first time was a normal transfer with full electrical power available.
.The second time included the failure of one emergency diesel generator (Note that the simulator has been updated to ensure that the modifications to the plant are included in the
- Millstone model).
' in addition to the procedures and training provided to the operators, the licensee stated
' that certain control board modifications were completed to enhance the operators' ability to perform the RSS swapover evolution from a modification to the cold leg recirculation j
array. The licensee stated that the Cold Leg Recirculation Array on Main Control Board #2 j
has been changed to provide the operator with an arrangement of control switches identical to the actions reflected in EOP ES-1.3. With this change, the operator can i
(complete all actions required for switchover from cold leg injection to cold leg recirculation
{
. at the array location.
j l
During the March 6,' 1998, telephone call, the staff asked the licensee if any measures
)
, were taken to minimize the likelihood of the operators, inadvertently closing the two spray-j header isolation valves (i.e., steps that were taken in the past during establishment of long-term recirculation). The licensee informed the staff that the switches associated with the '
spray header isolation valves were going to be fit' ed with a protective cover shield to l
t
~ inhibit inadvertent actuation. The staff considered this modification to be adequate to I
ensure inadvertent actuation was minimized.
Based on the NRC review of the licensee's response dated February 16,1998, and the answers provided during the March 6,1998, telephone call, the staff determined that the
!
licensee provided adequate justification for the proposed change, modified affected operating procedures, provided training to the operators on these changes, and provided i
sufficient information to demonstrate that the operators are capable of performing the j
required actions within the specified time. The staff had no further questions in this area.
'
c.'
Conclusions.
. The staff has reviewed the licensee's February 16,1998, submittal regarding the
,
modifications to the RSS, the information provided at the February 19,1998, public l
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meeting, and the answers to the' staff's questions during the telephone call on March 6, l
1998. Besides the identified USO associated with the modification made in 1986, which
!
! eliminated direct injection to the reactor coolant system (which will be reviewed I
- separately), the staff has determined that the modifications made to the RSS during the current outage under the provisions of'10 CFR 50.59 appear appropriate.
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In'a letter dated April 16,'1998,the NRC staff stated that eel 50-423/96-06-13and 97-202-09 were determined to involve violations of NRC requirements and could be considered for escalated enforcement and subject to civil penalties. However, the NRC stated that it would exercise enforcement discretion pursurnt to Section Vll.B.6 for eel 50-423/96-06-13 and Section'Vil.B.2 for eel 50-423/97-202-090f the NRC's Enforcement Policy, and not issue a formal Notice of Violation or Civil Penalty. Therefore, based on the above, eel 50-423/96-0613and 97-202-09 are considered closed. Also, as a result of previous
' inspections of the RSS issues documented in several inspection reports as noted above, and
,
the inspection results noted herein, SIL ltems 1 & 85 are considered to be closed.
I
' E2.1.2 RSS Containment Sumo Gans and Debris (LER 96-03!EQQ)
a.
Insoection Scooe (92700).
.
.
.
I The inspector reviewed the licensee's actions to correct the adverse condition reported in I
Licensee Event Report (LER) 96-039-00.
i b.
Observations and Findinas l
On October 15,1996 a licensee examination of the Recirculation Spray System (RSS)
containment sump was performed.' The inspection was deemed necessary since several wips and bolts had been found missing from the vortex suppression grating inside the sump.
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Debris was found in the ~ sump and in the 'C' and 'D' RSS suction lines. Subsequent l
' inspections on.10/22/96,10/26/96 and 11/7/96, revealed gaps in the deck plate closures
'. greater than 3/32 inch (Adverse Condition Report (ACR) M3-96-1008), gaps in the A/B train l
dividing screen greater than 3/32 inch (ACR M3-96-1101) and debris in the sump piping j
'(ACR's M3 96-0973 and M3-96-0974). Since the debris was of a size greater than allowed
{
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for in design, the possibility existed for a loss of recirculation' spray and/or ECCS function.
I during a Design Basis' Accident and.the licensee issued LER 96-039-OOto report the
- condition.
The root causes of the event were concluded to be: inadequate inspections during plant construction, startup and maintenance; a failure to define the critical design attributes of the sump cover plates and screen assemblies; and a weak Operating Experience Program.
As a response the licensee committed to: remove the debris; perform an engineering
'
assessment of the RSS sump; revise sump inspection, closeout and work procedures to stress critical design attributes; and evaluate the Operating Experience Program. To satisfy
' the commitments the licensee performed a comprehensive inspection of the sump in i
accordance with newly developed instruction 3DE-96-OOO9. The inspection revealed additionalinstances of excessive deck plating / screen gaps and debris, and sump component corrosion. The additional deficiencies were documented in ACR M3-97-0314.
L-Work Orders were next implemented to correct all documented deficiencies. This included j
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deck plating and screening modification and repair,' sump cleaning, RSS suction pipe clean j
out, rust removal and final area cleanup / painting. Surveillance procedure SP 3612A.1 was revised to enhance the description of sump critical attributes. A self assessment of the.
operating experience program was performed, its weaknesses defined and revisions made to
.
procedure NOOP 3.04 and instruction NSE 3.01 to improve the dissemination and use of j
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operating experience information. Preventative maintenance form 3704A-727 was
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- developed and issued to provide guidance for the removal and installation of sump deck i
plates to maintain design clearances. For completion, QC signed off for cleanliness.
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- The inspector reviewed procedure SP 3612A.1 and maintenance form 3704A-727, The
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changes to SP 3612A.1, and its associated inspection checklist, provide the visual
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inspection requirements for the sump components to assure that they are clean, undamaged l
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. and properly maintained. The maintenance form requires the establishment of a foreign -
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materials exclusion zone and the maintenance of design clearances during entry to the
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sumps. Taken together these documents provide an adequate basis to assure that the sump l
L and its decking and screens remain in a serviceable condition.
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The inspector reviewed procedure NOOP 3.04 and instruction NSE 3.01 Procedure NOOP 3.04 was revised to eliminate the need for individual LER reviews and to insure that OE
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.information is reviewed for and implemented in training programs. The revision to NSE 3.01 j
is the inclusion of a screening criteria checklist for disseminating OE information on a for
-information only basis. These revisions are meant to expand and expedite the distribution of i
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- OE information and should meet this intent.
!
.The inspector performed a visual inspection of the sump decking and screen exterior ~
l surfaces. No openings or gaps to the sump hterior, greater than 1/16 inch, were observed.
Indications of deck plate buildup, by weld addition and by the attachment cf filler plates,
!
were apparent, and the quality of workmanship appeared good. All surfaces were newly.
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painted. The Inspector concluded that the 3/32 gap criteria for deck and screen closures j
- was met.
l The inspector performed a review of the Low Pressure Safety injection / Containment.
(.
' Recirculation Syste'm Pl&D diagrams and discussed the history of system operations and '
!
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cleaning with the responsible licensee system engineer. The inspector determined that there l
twas a length of piping in each sump suction line that is not flushed during system surveillance testing and was not inspected or cleaned. The inspector concluded that these
- line segments could contain debris and needed licensee corrective actions.
l
~ in response to the inspector's concern, the licensee provided documentation to show that no
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- foreign debris was found in the area of the pump suction isolation valves during rework of those valves in 1993, and in subsequent repairs or adjustments of the valves as part of a L
. leakage rate testing program ' Coupling these findings with the fact that the distribution of
!
debris found diminished rapidly with distance from the sump drain, with none found in the L
leg just upstream of the valves, the licensee concluded that the line segments downstream
~
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. of the valves should be free of debris.
l H
To support this contention, and to satisfy the inspector's request for further corroboration, j
. the licensee performed a radiographic examination of the line segment in question for the 'D'
'aump suction line.. The radiographs showed no indication of debris. Next, to demonstrate
..the sensitivity of radiographs for debris materials, the licensee performed radiographic
!
examinations of pipes containing samples of debris. These radiographs showed that the i
' technique would detect any debris of the material types found during inspections, including i
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rubber gloves and ear plugs. The inspector concluded that the licensee had provided an i
adequate basis to infer that the line segments were free of debris.
c.
Conclusions The licensee has made physical modifications to the sump screen structures to bring them into compliance with design requirements, visually inspected and cleaned each sump suction line up t; its associated closure valve, and revised procedures to improve the inspection and maintenance of the sumps and to make better use of operating experience. The inspector considers these actions to be adequate. The sump suction lines have been cleared of debris exceedinn the allowable size criteria and the administrative measuras now in place should minimize < 1e likelihood of a recurrence of new debris accumulation.
Further inspectior, of this LER and its documented corrective actions was conducted during this report period by an ICAVP follow-up inspection team. The related inspection results and closure of LER 96-039-00 are documented in NRC team inspection ieport 50-423/98-205.
E2.1.3 RSS System Modification a.
Insoection Scope (37551)
The licensee implemented modifications of the RSS piping to improve system performance.
The modifications impacted the RSS vertical pumps. The inspector reviewed the licensee's actions to verify the design adequacy of the pumps in the modified system configuration.
b.
Observations and Findinas As a measure to correct flow problems associated with low NPSH conditions in the RSS, the licensee installed an orifice at the suction side of the expansion joint in each RSS pump discharge line. With this configuration, a noticeable increase in piping vibrations were observed during post modification testing, and resulted in a failure of a vent line on 3RSS'P1 A. Testing was continued until it was determined that a significant fraction of the fatigue cycle life of the 3RSS*EJ1 A expansion joint had been expended. With this realization, work was undertaken to relocate the orifice as a temporary modification to reduce vibrations. On disassembly, significant damage to the sleeve liner of the A loop expansion joint was revealed. Similar damage was found in the other expansion joint assemblies. The licensee concluded that the vibrations and the damage were caused by high flow velocities and flow cavitation induced at each orifice. After considering various options, the licensee decided to replace each expansion joint with a solid pipe spool piece as a corrective measure. Associated changes included some modification of the pipe supports in the vicinity of the pump and a redesign of the pump vent lines. To support the last modification, the licensee: revised the qualification calculations for the RSS piping; established new vibration acceptance criteria for the RSS pump and vent piping; and had the RSS pump manufacturer revise the qualification calculation for the RSS pump.
The inspector reviewed the qualification report for the 3RSS*P1 A,B,C,D pumps, " Seismic Stress Analysis Vertical Pump," manufactured by Sulzer Bingham Pumps Inc., analyzed by
{
Mcdonald Engineering Analysis Inc. dated March 29,1998. The analysis was performed in
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accordance with Stone & Webster Specification No. 2214.802-044,using nozzle loads consistent with the solid spool piece piping configuration, and the 1971 ASME, Section lil, Class 2, including Winter 1972 Addenda criteria and requirements. For flange and flange i
bolting analyses, the ASME Code Sections NC-3658 and Code Case 1828 were used.
For the analysis, a model of the pump was developed and processed using the finite element code ANSYS. Load and stress estimates were then combined to show compliance with ASME criteria. The inspector reviewed the model and the qualification calculations, and with one exception, found them to be appropriate. The exception was the use of ASME
' Section NC-3658.2 to qualify the flange bolting. This section is limited to moderate
. temperature and pressure applications and_the pump, with a temperature above 2OOF,-
exceeded this criteria. After consultations with NRC staff experts in code applications, the use of NC-3658.2 was determined to be conservative and accepted in this application.
The inspector performed a summary review of the calculation. Many inconsistencies were
~ found. in essentially every instance, the analyst was found to have used a more conservative value of a quantity, rather than its correct value. As an example of this, the analyst used a stress concentration factor of 2.43, rather than the correct value of 2.08,in
'the analysis of the discharge nozzle. In a few instances, where the discrepancy was non conservative, the impact on results was negligible. The analysis report would clearly have
,
benefitted from a more extensive narrative. The responsible licensee engineer documented the inspectors findings and the licensee's responses to them in CR M3 98-2326.
The inspector performed a review of the load inputs to the pump analysis. In addition to dead weight and pressure, the analyst considered the % SSE and SSE seismic load cases and nozzle loads defined by the licensee. The seismic loads were defined by the peak of the
_
input spectra as per the S&W specification. The nozzle loads were derived, by the licensee,
'
through analyses of.the piping attached to the pump. Included in the nozzle loads for the discharge nozzle, was a 30,000 lb. axial load induced by water hammer on the new orifice.
Since the water hammer impact load was a new, modification-specific load, the inspector reviewed Calculation 98-ENG-01581C3, Revision 0 and 98-ENG-01579C, Revision 0, which were its basis (98-ENG-01581C3 superseded 98-ENG-0157C3). The calculations are time history analyses of the pump and some of the attached discharge piping, subjected to a transient water hammer load of 100,000lbs., acting on the orifice plate. The analysis results indicated that the 30,000 lb. axial load, used in the pump qualification, was
- conservative. The inspector considered the calculation acceptable but recommended that an additional computation run be made. Specifically the inspector noted from time history plots of the response forces, that the response cycled at 100Hz. Since response frequency is a
- parameter that affects the definition of damping used in the analysis, and since the licensee had,used a value of 12 Hz for this parameter in their analysis, a need to evaluate the effect of a higher frequency approximation was apparent. Preliminary estimates of the impact of
~
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this change are that the force levels increase but the summary conclusion will remain the same.
The inspector' performed a brief review of the licensee's efforts to evaluate the RSS piping.
The revised evaluations include the new discharge piping support configuration (a rigid was replaced with a spring hanger) and the orifice induced water hammer load. The inspector
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confirmed that the licensee continues to comply with all previous commitments regarding
. piping design.
Because of the vent line failure on 3RSS*P1 A,the licensee implemented modifications of these lines, and established acceptance criteria for their vibrations. The modifications were designed to reduce the vibrations'and their impact. This was done by reducing the span length of the cantilever-like pressure taps and upgrading the size of the welds on socket
' joints The vibration acceptance criteria were based on application of the methods described
.
in the EPRI Fatigue Management Handbook and are essentially an extension of the ASME OM-3 methods to more complex configurations. Systems testing has demonstrated that the vent line vibrations are within the acceptance levels. The inspector reviewed Structural Integrity Associates Report No. SIR 98-033, Revision 0,' which documents the analyses, and the associated licensee independent review memorandum. The inspector considers the licensee's actions to be appropriate and concludes they should reduce the likelihood of new vent line failures.
Vibrations at the RSS pump, and in its near vicinity, received attention by the licensee. The inspector discussed these efforts with the licensee representative responsible for evaluating these vibrations and reviewed summaries of the measured vibration data. The data included measurements made pre and post orifice installation and pre and post expansion joint
.
- replacement. The data clearly shows that vibrations increased dramatically after the orifice was installed, almost reaching levels that were unacceptable per ASME OM-6 criteria. With the removal of the expansion joint the vibrations showed an equally dramatic decrease back
. to levels comparable to pre orifice levels. As explanation, it was conjectured that the flow turbulence created by the orifice excited a mode of. vibration of the expansion joint assembly. These vibrations excited or amplified vibrations of the pump and piping and resulted in the elevated vibratory response observed. With the joint removed there is no fle'xible component to respond to the orifice turbulence and more controlled vibrations are
~
observed.' The inspector considers this explanation to be logical and consistent with the data. 'New vibration acceptance criteria per ASME OM-6 have been developed.
c.
Conclusions The licensee has taken various actions to address different problems in the RSS system.
.The orifice addition created new, unforseen vibration problems. The removal of the expansion joint appears to have corrected these problems. The actions and analyses undertaken by the licensee in support of this action are considered appropriate.
L E2.2 (Closed) eel 96-201-15: Auxiliarv Feedwater Valves not Capable of Maintaining Containment intearity at Containment Desian Pressure ( Update - SIL ltem 18)
a.-
Insoection Scone (40500)
Concern about the design adequacy of the Turbine Driven Auxiliary Feedwater pump (TDAFW), discharge valves 3FWA* HV36A,B,C,D was raised during the NRC inspection of the licensee's past closure of these valves to isolate the TDAFW pump (3FWA*P2) at power levels less than 10%. The TDAFW pump isolation valves failed to fulfill the operability requirements of TS 3.6.3 " Containment isolation Valves." The referenced valves L
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are required to maintain the containment integrity by being leak proof at a back pressure of 38.6 psig during the design-basis containment accident.
Addressing the NRC finding which questioned the adequacy of these valves, the licensee contacted the valve vendor, Target Rock and inquired about the valve's ability to hold back-pressure. Target Rock stated that the valves were " unidirectional" and were not designed to isolate system pressure in the reverse direction. Upon receipt of this information from Target Rock, the licensee performed a preliminary operability determination which concluded that there was a reasonable assurance that the valves were capable of performing their containment isolation function. The licensee finding that the valves were adequate, was questioned by the NRC. Reacting to the second time that NRC questioned the design adequacy of the valves, the licensee performed a bench test of a spare valve and found that the valves became unseated and allowed reverse flow at 5 to 7 psid. As a result of the bench test, the licensee declared all four valves inoperable, in violation of TS and initiated a plant shut down. The valves were returned to the vendor where modifications were made to make the valves capable of holding the design back-pressure and meet the TS requirements.
b.
Observations and Findinas The inspector reviewed 12 ACRs and 4 DCRs associated with this eel along with other associated documentation and engineering drawings. ACR 10774 refers to ACR 12215 where the details of the modification to valves 3FWA*36A,B,C,D are described. The original TDAFW pump discharga valves 3FWA*36A,B,C,D would not remain closed when exposed to a differential back-pressure greater than 5 to 7 psig. These valves are 3 inch, normally open, solenoid-operated, modulating globe valves, which have now been modified to isolate reverse flow up to 1355 psi differential pressure. The inspector reviewed " Modify Target Rock Solenoid Valves 3FWA*HV36A-D"; DCR M3-9605 Rev. 0; and " Safety Evaluation Nurnber M3-96059-MCE". These documents describe how the valves have been successfully modified to withstand 1355 psid. These valves now await final testing during Mode 3.
The seismic qualification of the valves remains unchanged.
The inspector also reviewed valve drawings, which show the new configuration, and ccmpared the environmental qualification accident conditions with the specifications for the valve seals. The inspector reviewed the documentation that showed that the valves, in their new configuration, had passed their seat leakage test. No discrepancies were identified.
The inspector observed the modified valves during a walkdown of the TDAFW system.
c.
Conclusions The modifications to the referenced valves by the licensee are deemed adequate. The technical issues associated with eel 96 201-15 are considered closed. The NRC Notice of
. Violation (NOV - letter unique identifier 01112) currently remains administratively open.
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L E2.'3 ' (Closed) IFl 50-423/96-09-17 Emeraency Diesel Generator Exhaust Stack (Closed - SIL ltem 75)-
a.
Insoection Scooe (92903)
The licensee issued a Final Safety Analysis Report (FSAR) change request on April 11, 1995, that removed a licensing commitment to open the emergency diesel generator (EDG)
exhaust access hatch on receipt of a tornado alert. The licensee concluded that the removal l
of this requirement did not constitute an unreviewed safety question (USO) and, therefore, j-prior NRC approval was not required. In inspection Report 50-423/96-09,the inspector (.
reviewed the licensee's safety evaluation and various NRC correspondence to determine if
.
j-the proposed change was properly handled by the licensee. The inspector determined that
' additional review was needed with respect to the technical adequacy of the change and that
[
the issue would be considered an inspector follow-up item (IFl 50-423/96-09-17). The NRC i
staff has completed its review of the licensee's safety evaluation associated with the FSAR
'
change and the related response to the staff's request for additional information dated September 15,1997. The staff's conclusions are discussed below.
b.
Observations and Findinas The EDG exhaust stacks located outside the EDG building at Millstone Unit 3 are exposed to tornado generated missiles and have not been specifically designed to withstand such missiles. To address this concern during the initial Millstone Unit 3 licensing review, the licensee committed to provide an access hatch in the exhaust piping of each EDG. This access hatch would be manually opened during tornado. alerts and function as an exhaust i
.
bypass in the event that the exhaust stack downstream of the hatch is damaged by tornado
generated missiles. The access hatch is located in an exhaust plenum which has two i
'
openings, 66" x 100" and '48" x 168".
i l
Based on results of a 1985 probabilistic risk assessment (PRA), which concluded that the l
probability of significant demage to the EDG exhaust piping from tornado generated missiles-
!
is less than 10 per year, the licensee implemented an FSAR change to delete the above
cited licensing commitment (for reliance on the access hatch). The NRC staff rereviewed l
l the licensee's PRA, and based on that review, concluded that the PRA was only performed i
to estimate the risk of tornado generated missiles, which could enter any of the openings l.
(roof and east wall openings) in the exhaust plenums to cause damage to the EDG exhaust
'
system. ' The PRA did not address the probability of the relatively small portions of the EDG exhaust stacks located on the roof of the building being hit by tornado generated missiles, nor did it address the overall risk from tornado missiles at the plant. Therefore, by letter dated September 15,1997, the NRC requested additional information from the licensee to address these issues.
In responding to the NRC staff's request, the licensee performed an analysis to enhance the previously mentioned PRA by estimating the annual probability of tornado generated missiles impacting any portions of the exhaust stacks which are vulnerable to tornado generated missiles. By letter dated January 21,1998, the licensee provided a description and results of the analysis, which demonstrates that the annual probability of tornado generated missiles impacting portions of the exhaust stacks is about 108 per year with a corresponding l
!
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. damage probability of 10f per year. The probability of damage to both EDG exhaust systems is about 10-8 per year. The results of the enhanced PRA meet the NRC guidance
' described in Standard Review Plan (SRP) Section 2.2.3, " Evaluation of Potential Accidents."
p Similarly, as referenced by the licensee in its January 21,1998, letter, during the licensirg l
review of Seabrook, tornado generated missile impact to a given EDG exhaust stack was also determined to be 10-8 per year.~ The staff, in Supplement 5 to the Seabrook safety evaluation report, concluded that tornado missile protection was not required for the EDG exhaust stacks. -Therefore, based on the Millstone Unit 3 enhanced PRA and the Seabrook information, the licensee concluded that tornado generated missile protection for the portions of the EDG exhaust system vulnerable to tornado missiles is not required.
.The licensee also provided additional information by letter dated February 26,1998, to
- address the staff's request for additional information related to the overall tornado missile
. vulnerability of the Millstone Unit 3 plant. Although the licensee did not perform a PRA to l
address all unprotected structures, systems, and components, the licensee did provide additional information to demonstrate that adequate tornado missile protection for the overall plant was considered in the design of the plant, and was addressed in the original licensing basis./However, as a result of the licensee's review to address this issue, a single new target was identified for which administrative controls will provide adequate protection. The single new target is a recirculation loop for the demineralized water storage tank (DWST).
The DWST is missile protected and provides the suction source for the auxiliary feedwater
- system.. The line in question is automatically isolated on a loss of power condition.
However, if power remains available throughout the event, failure of this line due to a missile impact would result in loss of DWST inventory. Although the most likely tornado scenario of concern would involve a loss of power, to eliminate this failure mode, the 9 licensee plans to provide administrative controls to isolate this line upon receipt of a tornado warning. The inspector had no further questions regarding this issue.
,
c.
Conclusions.
The staff has reviewed the licensee's FSAR change, and based on that review, concluded that the results of the above cited PRA are consistent with the guidance described in NRC's SRP and that the use of the results from the PRA as a basis to delete the above cited licensing commitments is acceptable. Therefore, the staff finds the licensee's FSAR change
. and deletion of a licensing commitment acceptable. Based on these findings, IFl 50-423/96-
= 09-17 is considered closed. Since both issues (IFl 50-423/96-08-15and 96-09-17) covered
. by SIL ltem 75 have now been inspected (reference: IFl 50-423/96-08-15was closed in Inspection Report 50-423/98-206),SIL ltem 75 is hereby closed.
U3 E7 Quality Assurance in Engineering Activities E7.1 Review of items to be Comoteted After Restart (Closed - SIL ltem 40)
a.
Insoection Scone (37550)
in a letter dated April 16,1997, the NRC requested, in part, that the licensee provide the following information pursuant to 10 CFR 50.54(f):
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e; For each unit, the' list of significant items that are needed to be accomplished prior to -
restart; o.
For each unit, the list of items to be deferred until after restart; and, o
For each unit, the process and rationale used to defer items until after restart.
The letter also requested updates approximately every 45 days for the first two items.
Inspection Report 50-423/97-202 documented the NRC review of the Unit 3 initial submittal, dated May 29,1997, and the first update dated July 14,1997.- The NRC found that the licensee's determinations of items to be deferred was generally appropriate. However, three-items were removed from the deferred items list based on the inspection. The inspectors concluded the items would not have had a significant impact on plant operations had they not been completed prior to startup. The inspectors also identified problems with the i
completeness and accuracy of the submittal resulting in a notice of violation for failing to i
comply with 10 CFR 50.9, " Completeness and accuracy of information."
.The licensee provided the second deferred items list update for Unit 3 on October 21,1997 and NRC inspection of the update was documented in inspection Report 50-423/97-207.
This inspection focused on the items added to the list since the previous update. The I
inspectors had similar findings to those documented in previous deferred lasue reviews in
,
that the' licensee's determinations of items to be deferred was generally appropriate. As a result of this inspection'the licensee revised the status of four items from deferred to required prior to startup. The inspectors again noted that if these items had been deferred,-
j they would not have a significant impact on the safe operation of the plant.
The licensee provided the third deferred items list update for Unit 3 on January 9,1998.
. This submittal added approximately 2OOO items to the list. In February 1998 (Inspection
'l Report 98-206), the NRC reviewed the one line description of all the items added during this update ar'd then selected approximately 175 for more detailed review. The inspectors identified several discrepancies with the deferred items list and concluded that the licensee's evaluation' of the issues to determine if they could be deferred until after plant startup was
.I not fully effective.
The licensee provided the fourth deferred items list update for Unit 3 on March 17,1998.
This submittal added approximately 2000 items to the list. The inspectors reviewed the one line description of all the items added during this update and then selected approximately 160 for more detailed review to determine if the items satisfied the criteria for being
,
deferred until after restart.
The inspectors also reviewed a random sample of all open action requests (ARs) in the Action item Tracking and Trending System (AITTS). The inspectors selected a sample of 200 ARs, of a total of approximately 9600 open ARs, to determine if:
1)
items planned to be complete prior to restart were included in the significant items for restart section of the 50.54(f) submittal, where appropriate, or;
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2)-
items planned to be completed after restart satisfied the criteria for being deferred and, where appropriate, were included on the items to be completed after restart section of the submittal.
b.
Observations and Findinas The inspectors identified the following discrepancies during the review of the sample of items added to the deferred items list:
Condition report (CR) M3-97-2880,' associated with the electrical connection on valve
3FWA* AOV628, did not have the appropriate justification for deferral. The initial assumption by the licensee was that the connection affected a non-safety portion of the circuit. Based on additional review the inspectors concluded that deferral of the item could have been justified by performing an operability evaluation..However,
- during the inspection the necessary parts became available and the licensee reworked the connection to resolve the item.
An action request, associated with CR M3-97-3224,to perform a test sample using
the post accident sampling system was inadvertently included on the deferred items list Jue to an apparent administrative error. The work had been properly planned and scheduled to be performed prior to restart.
An action request, associated with CR M3-97-4131, tracked an action to clarify the
TS bases for venting the ECCS systems and was inadvertently left off of the deferred issues list due to an apparent administrative error. The item met the criteria for deferral.
An' action request, associated with CR M3-97-4571, documented the need to
. perform a surveillance test of the containment radiation monitor and was inadvertently included on the deferred issues list. Another identical AR also existed and was appropriately scheduled to be performed prior to restart.
The deferred issues list included UIR 1386 which was written to document the need
to provide a banis for the acceptance criteria contained in the surveillance test for the residual heat removal pump suction check valves. The licensee's basis for deferral included consideration of other testing which had been performed on these valves during the current outage. However, during the inspection the licensee decided to resolve this issue prior to the next performance of the surveillance test on the affected valves.
C
'CR M3-97-2998, included on the deferred issues list documents an issue involving
the ability to place the containment hydrogen monitors in service within the time
'
specified in the FSAR. The inspectors questioned why this item did not need to be i'
resolved prior to restart since the ability to meet the' design and licensing bases was in question. The licensee informed the inspectors that an AR had previously been L
initiated to track the performance of a FSAR change by May 15,1998, which will I
result in the issue being resolved prior to restart.
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,
I
The results of the review of the ranoan sample of open ARs was that the inspectors identified three ARs that should have been included on the deferred issues list. Statistically, i
these results indicate that there is a 95% confidence level that the AR compliance rato is better than 96E The inspectors noted that the items were technically acceptable for
,
_
deferral but failed to be included on the deferred issues list due to administrative errors in the AITTS data base.
c.
Cone'lusions The inspectors concluded that licensee evaluation of items for deferral was generally
> appropriate and reflected a conservative decision-making process. None of the items
. questioned by the inspectors would have resulted in a significant impact on safe plant operation if they had actually been resolved after plant restart. Although several minor,-
I generally administrative type errors were identified, the inspectors concluded that the
- accuracy and completeness of the deferred issues list was sufficient for the intended use by i
the NRC.~ Violation 50-423/97-202-08 is closed.
. During a previous inspection of deferred items, unresolved item 50-423/98-206-06 was r
opened to track an issue concerning the potential for a common mode failure of both residual heat removal pump minimum flow recirculation valves. The licensee' subsequently l
imp 5emented a modification to eliminate the potential failure mode. However, as discussed l
in LER 98-012-00,the licensee plans to perform an engineering evaluation by June 30, 1998, to further evaluate if the postulated failure mode was actually possible. This l
unresolved item remains open pending NRC review of the final licensee evaluation.
i l
l Reviews of items to be completed after Unit 3 restart, pursuant to the NRC 10 CFR 50.54(f)
l request, have been previously conducted and documented in inspection reports 50-423/96-
'
06,97-202,97-207, and 98-206. Additionally, the Operational Safety Team inspection (OSTI), documented in inspection report 50-423/97-83, conducted further inspection of the deferred items based upon licensee updated status lists and work progress. Based upon the results of the current review and continued evidence that the licensee has established and maintained an appropriate review process, SIL ltem 40 is considered closed.
I
- E7.2 : _ Modes associated with Maximum Ooeratina Pressure differe Review of ACR MP3-96-0821. Analysis of Solenoid Operated Valves (SOVs) Failure (
l SIL ltem 60)
Insoec' ion Scope (92903)
'a.
t The quality assurance (QA) status of air regulators and solenoid operated valves (SOVs) in the Instrument Air System was found to be inconsistent between the MEPL evaluations'and the PMMS Bill of Material (BOM) listings. The PMMS BOM for the air operated control
' valves (AOV) erroneously showed the SOV as a nonshfety-related (NSR) item. This situation led to performing non-QA repairs / replacement on a safety related (SR) SOV. ACR MP3-96-
'0821 recommended that the SR SOVs be removed from the BOM for all NSR AOVs and that
_they be listed as a separate item in PMM _
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b.
Observations and Findinas-
~ Tlee inspector reviewed ACR MP3-96-0821,the Corrective Action Plan of ACR MP3-96-
,
0821, associated engineering drawings and documelts, and the licensee's implemented corrective actions.
cA previous ACR, MP3-96 0718, caused 48'SR SOV to be upgraded so that their Maximum Operating Pressure Differential (MOPD) rating of 60 to 75 psig wocid match the full air
' system air pWssure of 110 psig that the SOV would be subjected to if the NSR air regulators failed. The process of upgrading the MOPD ratings of the SOVs led to the discovery that a
. number of SR SOVs were identified as associated with NSR control valves / dampers. The'
,
PMMS BOM for some AOVs incorrectly included the SOV as a nonsafety-related item even
.though the SOV was listed in the MEPL as safety-related. This ACR - MP3-96-0821 corrects the MEPL and PMMS Bill of Material listings for those SOVs which are safety related. The solenoid operated valves are small three-way valves which control the air inlet to larger AOVs to which the SOVs are usually attached. Showing the small SOV as a NSR item in the BOM of the AOV has led to the performance of non-QA repairs or replacement SOVs.
Additionally, in some instances the BOMs for SR AOVs erroneously listed SR SOVs as NSR items.
1 A new determination of the proper SOV safety classification and the levsl of quality
. assurance required, was made under MEPL No. MP3-CD-0983. The licensee updated the -
PMMS to add component identification numbers to SR SOVs, where these ids had not already been assigned by a previous MEPL evaluation. SOVs were then deleted from the parent AOV component BOM. The solenoid valves now have a local ID and their o"vn BOM.
'
The licensee elected to treat all the SOVs the same and remove them from the BOM.of the.
AOV regardless of whether or not the SOV was safety related.
The licensee also underto:,k a review of work order histories to ascertain if there were any-instwes of non-QA work being improperly done on a QA related component and found one icase. ACR MP3 97-0415 was issued requiring the solenoid valve, with a history of non-QA
.
- work, to be replaced under a QA work order.
The inspector made a spot check to verify that SOVs were removed from the BOM of AOVs and found one AOV valve that still had an SOV on its BOM. Further checking by the inspector revealed that the only SOVs removed from the AOV BOMs were those SOVs
,
serving an AOV which had a diaphragm. Limiting the BOM changes to AOV valves with
[
^ diaphragms was contrary to the intent of the ACR corrective action plan, item 1, which l'
stated the need to assure that an SOV did not appear in two places. The licensee reviewed
[
. this condition and issued CR M3-98-1135 to correct the BOM and the MEI'L. The plan for this CR M3-98-1135 has been completed.
The air regulators, to the AOVs used in the Instrument Air System, were also included in each AOV/ damper BOM. These air regulators, supplying regulated air to both the SOVs and
' the AOVs, are nonsafety-related. ~ ACR M3 96-0944 required the licensee to re-evaluate the QA status of the air regulators, supplying air to the solenoid operated valves. The issue in question was, if all the control systems in NSR instrument air failed, the air pressure would go up to'125 psig, and may damage the SOVs. The inspector reviewed Engineering
'u
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Evaluation, M3-EV-960015, Rev.0, and Mechaaical Review, MP3-DE-96-762, wherein the ali regulators were evaluated by the licensee end found to be NSR components. The rationale used by the licensec was based on the uniform assertion by the AOV vendors that their valves could ha pressurized to 125 psig and, while some damage may occur, they could still perform their safety function.
c.
Conclusions -
The licensee reviewed the PMMS and MEPL entries for all QA Category 1 control valves, dampers, and SOVs to assure that these lists were consistent. PMMS, the MEPL evaluations, and the BOMs have been changed to show the AOVs and the SOVs with the correct safety designation. The licensee also deleted the SOVs from the AOVs' Bill of Materials to avoid double !! sting of the SOVs under both the AOV and the SOV identification. The inspector also reviewed the documentation of the corrective actions done for the one SR valve found to have had non-QA work performed on it. These changes were found to be acceptable. The inspector has nn further questions regarding the followup of l
corrective actions for ACR M3-96-0821. SIL ltem 60 is hereby closed.
U3 E8 Miscellaneous Engineering issues
. E8.1 (Closed) LER 96-034-01: Residual Heat Removal Pumo Suction Relief Valve Setooint Not in Accordance with Technical Specifications a.
Insoection Scope (92700)
In addressing LER 96-034-01,the licensee committed to provide an evaluation of the
_
Residual Heat Removal (RHR) relief valve setpoint effect on the RHR pump stress analysis; to revise the associated setpoint calculation in order to properly incorporate the RHR pump suction relief valve temperature correction for the full temperature range; and to provide a supplement to the investigation into the cause of this event.
b.
Observations and Findinos l
l-The inspector reviewed LER 96-034-01 as well as Change Request Action Closeout M3-97-2864, Assignments 97021701-07,-05, and -08. Per assignment 97021701-07, based on Calculation No.12179-P(R), Rev. O, CCN 2, the relief valve setpoint change would change the transient upset pressure from 600 psi to 660 psi. The 60 psi increase caused an j
'
increase in stress in the 10.75 inch pipe of 441.78 psi which, when added to the calculated
,
l stress in the pipe of 15,690 psi, is still less than the allowable pipe stress of 19,440 psi.
!
'
Per assignment 97021701-05,the setpoint calculation to properly incorporate the RHR pump suction relief valve temperature correction for the full temperature range was I
completed and the RHR Pump Suction Relief Valve Surveillance Testing procedure was revised and implemented. Per assignmsnt 97021701-08,a supplemental report to this LER was issued by the licensee resulting in the NRC issuing Amendment 143 to the Facility Operating License No. NPF 49, revising the setpoint of the residual heat removal suction relief valves.
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c.
- Conclusions -
'The licensee's corrective actions in response to this event, as documented in the LER are acceptable. LER 96-034-01is considered closed.
E8.2 LClosed) LER 97-047-00: Failure to Comoletelv Test the Thermal Overload Bvoass
'
. Protection Loaic of Safetv-Related Motor Operated Valves that Receive Multiole Actuation Sianals s.
Insoection Scone (92700)
,
LER 97-047-00 was reviewed and left'open in inspection report 423/98-206,pending the rsvision of procedures and the appropriate testing of MOVs CCP"MV222 through 229 and-SWP'MV115A/B.
b.
Observations and Findinos The inspector reviewed Surveillance Procedure SP 3674.1, " Motor Operated Valve Thermal Overload Bypass Testing," and the MOV Thermal Overload Testing Data. The MOV test
- procedure was found to be adequate and the MOV test data showed that all valves passed
'
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their thermal overload bypass test.
c.
. Conclusions
.' All issues have been acceptably addressed. LER 97-047-00is closed.
L E8.3' (Undate) LER 97-050-00: Non-Environmentally Qualified Parts Installed in Safety Related Comoonents
l a.
Insoection Scoon (92700)
LER 97-050-00 identified that non-qualified parts were installed in safety-related feedwater isolation valves (FWlVs) 3FWS*CTV41 A, B, C, and D during their last 5-year preventive
. maintenance (PM) schedule. The scope of this inspection is to verify licensee's proposed
' corrective actbns.
- b.
Observations and Findinos l-On August 23,1997, while evaluating the Materials Equipment and Parts List (MEPL) the
. licensee found that the feedwater isolation valve (FW:V) 3FWS*CTV41 A(a safety related valve) had used a commercial grade (non-QA) part W30572 during its 5 year PM schedule.
Later Work Planning and Outage Management (WP&OM) identified that Electrical
,
Environmental Qualification (EEO) requirements were not included within the part level MEPL evaluation program and.the current procurement processes may not maintain EEQ program requirements for non-QA parts. A Level 2 Condition Report (CR M3-97-2779)was issued and later was upgraded to Level 1 on September 25,1997. As a result of compensatory actions implemented for this CR, several " daughter" CRs were generated. One of these CRs
,,
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was CR M3-97-3301 which resulted from a review of 3FWS*CTV41 A & B preventive maintenance work orders (M3-92-22193 and M3-92-221951 and determined that non-EQ parts were used for these safety valves. This CR was also upgraded to a Level 1 status on October 23,1997 and LER 97-050-OOwas issued on November 15,1997 where all four FWlVs were mentioned to have this problem.
The'cause for this LER was a program deficiency relating to the Production Maintenance and
. Management System (PMMS) and the parts procurement process for non-QA items in EEQ
- components. In an accident under full flow condition, the FWlVs are required to close within 5 seconds after receiving an actuation signal. Until now, no failure was reported in any of these four valves even if they had non-QA parts. The licensee claims that the safety-related FW flow control (or regulating) valve and the bypass level control valve, located upstream of the FWlV, can automatically isolate the system on receiving a feedwater isolation trip signal and thus, provide another reliable means to isolate the FW system. The proposed corrective actions are: (1) The FWlVs will be inspected and unqualified parts will be replaced, and (2) A review of all open automated work orders (AWOs) and a representative sample of closed AWOs associated with non-QA and environmentally qualified components will be conducted to ensure the adequacy of replacement parts requirements. (3) Non-qualified parts will be replaced with qualified parts, as applicable.
Finally, (4) the EEQ programmatic issues that led to the non-qualified parts installed in the FWlVs are to be resolved as part of the corrective action plan.
AWOs M3 92-22193,22195,22197,22198 describe the actual maintenance activities that
.were carried out to correct the problems associated with the four (A,B,C,D) FWlVs. The AWOs have inspection sheets which summarize all EEQ parts that were replaced or refurbished. For each valve, this list includes 4 three-way Skinner solenoid valves,1 air check valve, and 8 seal rebuild kits for various components in the FWlV. During this review,
~
the inspector found the QA sheet for the A-valve was incorrectly marked as B-valve fer the 4 solenoid valves replaced during this maintenance. On 3/20/98, an AWO change record
~ (Attachment 6) was issued to correct this discrepancy in the QA sheet.
Based on the valve drawing, there are two hydraulic needle valves which control the feedwater flow rate: one controls the closing of the valve (a safety function) and therefore is classified as safety related; and the other controls the opening of the valve (a nonsafety-function) and hence is nonsafety-related. While reviewing the Equipment QualificaWen Record (EOR 232-0-1,Rev.O) on these valves, it was discovered that the safety related needle valve had the non-safety valve's part number. DCN DM3-OO-OO10-98 dated 1/5/9P, corrected the EQR ( earlier known to be Component Replacement Schedule -CRS) with the l part number for the safety related needle valve and issued the EQR # Rw,1. Although this is not the reason why non-QA parts were used in their last PM, this error coula hm c9used a similar problem in future maintenance activities.
The inspector examined the P&lD. of the FW system (Dwgs.12179-EM-1300-12 & -130C-14) and the physical locations of these valves. All four main FW lines were located on the second ficor of the Main Steam Valve Building. Each line has a flow regulating valve and a bypass valve, and a few feet downstream, the FWlV. The bypass valve is normally closed, while the other'two valves are normally open. The power supply to the regulating valve is
- from a different power supply train from that of the isolation valve. On a FW isolation
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signal, both these valves close in 5 seconds. If the FWlV would not close because of non-EQ parts failure, the flow regulating valve could have provided the necessary isolation.
However, the system would lose its redundancy status.
Since the issuance of the LER in November,1997, the licensee has reviewed all AWOs issued since initial plant licensing. This included both open and closed AWOs. Out of 2103 L
open AWOs, only 1125 of them had been processed for replacement parts at the time.
Only 4 AWOs were found having EEQ parts deficiencies. Two CRs (CR M3-97-4268 and l
4292) were issued to address these deficiencies. Appropriate actions have been completed to correct these deficiencies; All of them, including those already processed for parts, will again be reviewed by the EEQ Planning Group during close-out review and parts used will be identified at that time. Similarly, about 11,000 closed AWOs associated with parts replacement (out of 56,000 total) were compiled for review, These were further reviewed
- to determine those related to EEO. The final sort included about 325 PM EEQ AWOs and about 350 non-PM EEQ AWOs. After reviewing them, no AWOs were found to have an EEQ parts deficiency problem. The U3 EQ representative also reviewed a large number of AWOs in both PM and non-PM categories and found no discrepancies.
The inspector reviewed the programmatic changes in the work planning process so that such occunences can be prevented at tne maintenance planning stage. Once an AWO is initiated, a dedicated EQ person reviews and verifies the EEQ part numbers for all
,
'
replacement parts. He determines the classification of these parts (EQ or non-EO) and sends the parts list for procurement. He also verifies the parts, after the maintenance has been completed, assuring that appropriate parts have been used in the equipment. His primary
. role is to verify the part numbers (both non-QA or QA) for all replacement parts on EEQ components from the PMMS. Thus, it is imperative that he has proper qualification to understand the EQ process, specifically the use of the nuclear and program indicators (Nis and Pls).. At the time of interview, he seemed to have some knowledge on the OMMS and j
both indicators. He, along with other members of the group, are scheduled to take EQ-related classes in the upcoming EPRI training series given at their maintenance center in
>;
North Carolina. The inspector noted that the person in this position did not have' training on the site-specific EQ process as part of the programmatic changes, as committed in the LER.
The' licensee has not yet addressed the EEQ programmatic issues identified in their root
' cause analysis report for preventing any recurrence of similar events in fmure. Some of these programmatic changes include EQ treining of personnel, developing procedures and guides, completing databases, and establishing management level support.
Typically, only.the EEQ parts of qualified life'less than 40 years of safety related equipment are docuraented in the EQR. EOR 232-0-1 for the four FWlVs contains 13 individual parts, and based on EQ testing, each of them has a qualified life of 10 years or 250 actuatcr cycles (whichever comes first).- The actual actuation cycles of these valves are being
_
maintained by the system engineering group and each month a usage report is generated for assessing their design life. The system engineer reviews this information during each plant's
~ refueling outage. If the actual cycles from the last PM or CM e in the proximity of the EO-qualified cyclei the system engineer flags the component for repecing the part during next scheduled maintenance. There is no documentation or procedure in the system engineering
- group to formalize this action. The WP&OM group also does not have any procedure or i
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i
guidance to handle this situation. Therefore, a condition report (CR M3-9s -1526) was initiated on March 19,1998, to rectify the problem associated with the 4 FWlVs. However, this particular concern can result in a generic problem to all parts that are dependent on the life cycles instead of qualified life in years and should be addressed as a programmatic issue
)
by the licensee.
l l
- c.
Conclusions
,
~ The licensee has completed the replacement of non-QA parts in all four feedwater isolation.
j
. valves. All open maintenance work orders at the time were reviewed and two CRa were
'
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. issued to correct the deficiencies relating to four safety-related solenoids. Computes sorts
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on all completed maintenances work orders were conducted to identify non-QA EEQ parts.
a Out of about 650 items,' 32O replacement parts were reviewed to determine their QA status.
LThe WP&OM personnel found that about 230 of them needed to be reviewed further by the EQ personnel. No additional discrepancy was found as a result of this EQ review. The inspector concluded that the corrective actions taken by the licensee are appropriate.
The inspector concluded that implementing corrective measures to address the EEO
, programmatic issues is necessary for the complete closure of this issue. Therefore, LER 97<
- 050-00 remains open pending acceptable resolution or scheduling of the EEQ programmatic
' issues and the life cycle issue noted above.
. E8.4 ; (Closed) LER 97-056-00: Service Water System Drainaae Followina a Containment Deoressurization Actuation and Loss of Power Could Result in a Condition Outside the Desian Basis of the Unit a.
Insoection Scooe (927001 LER 97-056-OOidentified that during a design basis accident coincident with a loss'of power, a potential inability to re-establish Service Water (SW) flow to the Control Building air-conditioning (A/C) Condensers (3HVK'CHL1 A/B) exists. The scope of this inspection is to verify licensee's corrective actions including design modifications.
- b.
Observations and Findinos.
!
- On November 7,1997,'during a review of original construction era SW Design Deficiency
' Reports,it was determined that following the initiation of a Containment Depressurization
"A" (CDA) signal coincident with a loss of offsite power (LOP), SW system pressures may not be sufficient to refill the vertical SW supply piping to the control building A/C
'
- condensers (CR M3-97-3788). If this happens, air temperatures within the control building could rise high enough to adversely affect the operability of safety-related equipment. The unit has not experienced this accident scenario since its original licensing and SW flowrate l testing at each refueling outage does not replicate design basis conditions (e.g., a degraded e SW pump, high SW strainer differential pressure, and a low intake water level as well as a LOP). This event is considered to be attributable to a design deficiency in the SW system
- (Root Cause investigation for CR M3-97-3788).
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100 l
in the event of a loss of coolant accident (LOCA) or high energy line break (HELB) accident, a CDA signal automatically closes the normally open valves 3SWP*MOV50A/B and j
3SWP'MOV71 A/ Bin the SW supply lines to the reactor building component cooling water
'
--(3CCP*E1 A/B/C) and turbine building component cooling water (3CCS*E1 A/B/C) heat
!
exchangers. At the same time it automatically opens normally closed isolation valves l
3SWP'MOV54A/B/C/ Din the SW supply lines to the containment recirculation spray L
(3RSS*E1 A/B/C/D) heat exchangers. Valves 3SWP'MOV54A/C are in train A and
> 3SWP'MOV548/D are in train B. The RSS pumps (which provide flow on the shell side of
'
the RSS heat exchangers) are not started for approximately 11 minutes after the CDA signal, and take approximately another 3 minutes to fill the RSS system. This 11 minute delay is to
allow sufficient time to accumulate water in the containment sump. Thus, there is a j
maximum delay of 15 minutes before the recirculation spray becomes effective (DCR M3-97045).
Ths SW system provides cooling water to the control building A/C condensers. On a LOP, I
SW flow is lost for approximately 30.5 seconds until the SW pumps are powered from the f
emergency diesel generators (EDGs). Due to the high location (Elevation 71' above Mean Sea Level (MSL)) of the control building A/C condensers (3HVK'CHL1 A/B), drainage may
'
occur during this 30.5 seconds. ' Based on the piping configuration, booster pumps 3SWP'P2A/B (Elevation of 66' above MSL), which assist the main SW pumps to ensure sufficient SW flow to these condensers, must overcome a static head of approximately 77 feet. In the original design, the SW system response to a CDA signal coincident with a LOP in which all four SW MOVs (MOV54A/B/C/D) supplying the RSS beat exchangers open immediately and simultaneously has inadequate system pressure to refill the supply piping leading to the control building booster pumps. In order to have sufficient SW system
,
pressure to prime these booster pumps, the licensee has modified (par DCR M3-97105)the
. control circuits for MOV54C&D so that they will have 3 minutes delay in opening after
~
receiving a CDA signal. The licensee's thermo-hydraulic calculation (Proto-Power Calc.#97-160, Rev.0) shows that this time delay will provide enough system pressurs to ensure
)
adequate volume to the booster pumps associated with control building A/C condensers.
- The inspector reviewed the relative sequence of events following a CDA signal coincident with a LOP after implementation of the DCR modification. Within the first 10 seconds after the LOP,3SWP*AOV39A/Bvalves open providing flow to the EDG heat exchangers when the SW pump power supply busses would be energized. EDGs start immediately after a LOP and take 10 seconds for the breaker to close and supply emergency power. Once -
energized, the open SW pump discharge valves (3SWP'MOV102A/B) start to shut in preparation for SW pump restart;'3SWP*MOV50A/B and 3SWP'MOV71 A/B start to shut to isolate flow to the CCP and CCS heat exchangers, respectin.ly; and 3WTC' AOV25A/B and 3SWP*MOV 115A/B start to shut to isolate non-seismic piping. Furthermore, due to CDA
. signal,3SWP'54A/B start to open to provide flow to two of the four RSS heat exchangers.
After eil MOV102 valves are closed in 20.5 seconds, one SW pump per train
'l
(3SWP*MOV54A/B) starts and the pump restart is interlocked with actuation of the
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' MOV102 valves. Therefore, the corresponding valve to each SW pump will be full open in another 20.5 seconds (or 41 seconds after the EDG is energized). The control building booster pumps (3SWP.*P2A/B) start approximately 90 seconds (DCR M3-97097, Rev 1)
i f.~
after diesels energize the bus. Thus, delaying the opening of SW MOVr 3SWP'MOV54C/D L
,
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101 until 3i10% minutes ensures that the booster pumps will be primed by the SW header -
pressure in 17 seconds and operating before the other two RSS valves open.
J As a result of this modification, the licensee has re-analyzed design of the piping system with higher SW system pressures and flows and found them acceptable (CCN#2 to SDP-SWP-01370 and CCN#5 to 12179-935P(T)). Since the flow conditions through MOV54A/B are greater, the design basis calculations are revised (CCN#2 to SWS-MOV-1380-M3)to reflect the new flows, it was determined by the licensee that these increased flows do not affect any MOV testing or the torque requirements.
' One Agastat (Time delay relay,120 vac,10 amp,60 hz, model #E7012AFOO4) unit is added to each control circuit of the motor operated valves MOV54C/D (DCNs DM3-OO-
-1746/1800-97, AWOs M3-98-OO457/461). The relays are mounted in the rear section of the Main Control Board 3CES*MCB-MB2in accordance with electrical spec SP-EE-076.
After installation, the licensee tested the functions of these devices and verified that there are no unexpected responses'when a CDA signalis given. Both valves were also stroke tested.
The licensee has reviewed two other open systems, the quench spray system (OSS) and the containment recirculation spray system (RSS), to ensure that similar flow problems do not exist due to drainage ~on an LOP. Based on calculations (US(B)-225), an LOP will not result in any draining or formation of void pockets in either the suction or discharge piping of the QSS system. Calculations US(B)-270 indicated that an LOP and RSS pump trip will not
._
cause any draining of the pump suction piping but would result in a voided pocket in the
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pump discharge piping between the pump and heat exchanger inlet. The effect of restarting the RSS pump after formation of this void is examined by Calc NP(B)-163-FA on water
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hammer analysis and found no particular problem.
L c.
. Conclusions
Licensee calculations and design changes demonstrated that in the event of a CDA j
coincident with an LOP, the service water system will be able to restart the booster pumps
and supply cooling water to the control building A/C condensers. The inspector concurs with this conclusion; hence, LER 97-056-00is consid6 red closed.
!
i E8.5 ] Closed) IFl 94-11-09: Erosion of Cement Under Containment Base Mat l
!
This item was opened in 1994 to review and follow up the observed erosion / leaching of j
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cement from the porous drainage concrete layer under the structural concrete. The j
inspector reviewed the documentation of the engineering studies performed by the Millstone
>
3 engineering staff and outside consultants, and discussed the status of the item with l
Northeast Nuclear Energy Company Engineering (NNECO) personnel.
'
Based on the above review of documentation and discussion with responsible onsite engineering personnel, the inspector determined that because the item involves a long term
,
design issue, it has been transferred to NRR for review and resolution (TAC No. M96402).
Northeast Nuclear Energy Company submitted information regarding this item and the associated safety evaludon to NRR on December 19,1997. The NRC requested additional l
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102 information regarding this item from NNECO by letter dated February 24,1998. The inspector verified that this item was being tracked by NRR as item number 12 on the Millstone Restart Assessment Significant item List (SIL). Because it is a long term design and licensing issue that needs review and resolution by NRC, and is being tracked by the
SIL, the current open item ( IFl 94-11-09) needs no further regional inspection follow up.
The item will be tracked and followed-up as part of SIL ltcm 12, which currently remains open and is under review by NRR.
Based on the above observation and finding, inspector follow-up item IFl 94-11-09 is considered closed.
t IV Plant Support (Common to Unit 1, Unit 2, and Unit 3)
-R1 Radiological Protection and Chemistry Controls R1.1 Implementation of the Radiological Environmental Monitorina Proaram (REMP)
.a.
Insoection Sesoe (84750-2)
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-The following areas of the REMP_ were assessed and reviewed:
selected sampiing and analysis procedures;
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' analytical data from 1997 and 1998; selected sampling techniques; -
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= operability and calibration of air samplers;
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1997 Land Use Census results;
.
1996 and 1997 (' raft) Annual Radiological Environmental Operating R'eports, d
-
b.
Observations and Findinas The inspector reviewed selected sampling and analysis procedures and toured selected sampling stations. The procedures provided appropriate guidance to perform REMP tasks.
The air sampling equipment and water compositor were operable during 1997 to present, as
, evidenced in the sample logs and sample analysis results. The air sampling equipment
, calibration results were within the established tolerances, and calibrations were performed
' within the frequency specified in the procedure.
,
The inspector reviewed the 1996 and 1997 Land Use Census. Each census was performed during the growing season as required by the Radiological Effluent Monitoring and Offsite
- Dose Calculation Manual (REMODCM).
The inspector reviewed the 1996 and 1997 (draft) Annual Radiological Environmental-Operating Reports. The reports included results of the environmental monitoring program,
- program changes, land use census, and interlaboratory comparison program, as required, iThe reports provided a comprehensive summary of the results of the REMP around the site and met the REMODCM/TS reporting requirements. Changes to the location of the control
- goat milk stations were made in mid-1997. The details of the REMP changes were
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103 describe,1 in the 1997 (draft) annual effluent release report, as required. The licensee also conducteJ a Radiological Environmental Review to verify that no Unreviewed Safety Question existed. The Radiological Environmental Review was thorough.
c.-
Conclusions The licensee effectively maintained and implemented a radiological environmental monitoring
. program in~accordance with regulatory requirements.
R1.2 Implementation of the Meteorological Monitorina Proaram a.
Insoection Scope (84750-2)
The following areas of the MMP were assessed and reviewed:
meteorological monitoring equipment calibration procedures and results;
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- data availability and data acquisition capability;
-
LCO logs from Units 2 and 3;
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daily channel checks and weekly channel functional tests for 1997 from Units 2 and
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3; modification of the meteorological data link to the process computer; and
-'
design chans e safety evaluation
-
- b.
' Observations and Findinas The inspector verified system operability, calibration status of the meteorological instrumentation, and reviewed the associated channel calibration and channel functional test
. procedures and results. Calibrations', channel checks, and functional tests were performed
,
within.the frequency recommended in Regulatory Guide 1.23, Revision 1. The wind speed, j
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wind direction, and temperature sensors on the towers were operable; data was available.
The procedures provided the appropriate guidance to perform channel functional tests and channel calibrations for all the channels, except for measurement of the instrument minimum accuracies of the wind speed channels.
I The instrument minimum accuracies of the meteorological monitoring instrumentation i
channels twind speed, wind direction, and delta temperature) are required be measured as l
part of the calibration operations. The inspector identified that the licensee had not
!
I performed the channel calibrations of the wind speed channels prior to April 24,1998 and, therefore did not meet the intent of the instrument minimum accuracy of the wind speed L channels, as required by TS 3/4.3.3.4, Table 3.3-8. The wind speed transmitters (sensors)
. were sent to the vendor where the sensors were subjected to accuracy and starting speed
, tests at the laboratory. This calibrated the sensor only.
. A channel calibration, according to the definition in TS 1.9, "shall be the adjustment, as necessary, of the channel output such that it responds with the necessary range and i
accuracy to known values of the parameter which the channel monitors. The channel calibration shall encompass the entire channel including the sensor and alarm and/or trip
[
functions, and shall include the channel functional test." Relative to wind speed, the
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I 104 licensee's calibration did not verify the entire channel, as required by the Technical Specification. Therefore, the accuracy of the wind speed channels were not measured during channel calibrations. Failure to measure the instrument minimum accuracies for the wind speed channels constituted a violation of Table 3.3-8 of Unit 2 TS 3/4.3.3.4. (VIO 50-336/98 207-16)
The licensee identified, duiing a QA audit, that the calibration procedures were not approved -
by the Safety Operations Review Committee (SORC). Technical Specification 6.5.2.6.a.
states, in part, that the SORC shall be responsible for review of all common site procedures
]
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required by Technical Specification 6.8 and changes thereto. Section 6.8 of the TS
.
requires, in part, that written procedures shall be established and maintained covering activities recommended in Appendix A of Regulatory Guide 1.33 (RG 1.33), November 1972. Appendix A of RG 1.33, " Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors," described typical procedures for control of measuring and test equipment and for surveillance tests, procedures, and calibration. The QA Audit Condition Report was issued on March 13,1998. In response, the licensee initiated action to have the calibration procedure reviewed by SORC. The procedure was approved by SORC on April 29,1998. The inspector conducted an in-office review of the procedure on May 4,1998.
No discrepancies were identified.
The failure to review and approve the calibration procedures (wind speed, wind direction, and delta temperature) for the meteorological instrumentation by SORC was a violation of TS 6.5.2.6.a. However, 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 Poliev. (NCV 50-245:338:423/98-207-17)
The inspector reviewed the licensee's Design Change Package (DCP) and Safety Evaluation regarding the Unit 3 modification of the meteorological data link to the Plant Process Computer (PPC) for the enhancement. The DCP and Safety Evaluation were thorough and '
complete.
c.
Conclusion (1)
The inspector identified that the licensee failed to measure the instrument minimum accuracies for the wind speed channels, as required by Table 3.3-8 of the Unit 2
' Technical Specification 3/4.3.3.4, constituting a violation of regulatory requirements.
(2)
The licensee identified that SORC failed to review and approve the calibration procedures (wind speed, wind direction, and delta temperature) for the meteorological instrumentation, as required by TS 6.5.2.6.a. This licensee-identified and corrected violation constitutes a Non-Cited Violation.
R7 Quality Assurance in Radiological Protection and Chemistry Activities R7.1 Quality Assurance Audit Proaram a.
Inspection ' Scope (84750-2)
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105 The inspector reviewed the following audit reports:
1:
. Nuclear Oversight Audits & Evaluation Audit report,1998; and
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Nuclear Safety & Assessment Audit Reports, 1996 & 1997.
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b.
Observations and Findinas The audits were performed by the Nuclear Oversight group. The objectives and scope of the audit covered specific areas of the REMP and MMP. The technical detail and quality of the audits continued to improve, as evidenced by (1) the detail of.the findings and (2) the number of observations, recommendations, findings, and condition reports. The auditors l
questioned the processes of the programs and identified programmatic weaknesses.
j Program strengths were also identified and documented.
Several findings and deficiencies were documented in each audit for the REMP and MMP.
The findings and deficiencies for the 1996 and.1997 audits were closed. One of the
!
. findings in the 1998 audit identified the lack of management oversight and ownership of the Meteorological Monitoring Program. As part of this audit finding, a Condition Report had L
been issued which described a deficiency involving the meteorological calibration procedures and the fact that they had not been reviewed and approved by SORC. (Section R1.2 pertains) The finding was appropriate.- Corrective actions were implemented, c.
Conclusion The licensee met the QA audit requirements. The audits were thorough and of sufficient depth to assess the strengths and weaknesses of the REMP and MMP.
R7.2 Qy.plity Assurance of Analvtical Measurements a.
. Inspection Scope (84750-2)
/ The inspector reviewed the following aspects of the QA/QC program of the primary contractor laboratory:
the QA program (internal audits)
-
- the results of QC program (split, duplicate, blind samples);
-
the_results of the Interlaboratory Comparison (cross-check) program; and
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the semlannual QA reports,
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b.
' Observations and Findinas The OA/QC program for analyses of REMP samples is conducted by the primary analytical contract laboratory, Duke Engineering & Services Environmental Laboratory (DESEL),
formerly Yankee Atomic Environmental Laboratory (YAEL). The inspector toured the laboratory and discussed with the personnel, any changes that may have been implemented since the new company purchase. The laboratory continued the programs as usua _ _ _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _
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106 The laboratory has interlaboratory and intralaboratory QC programs. The intrataboratory QC program consisted of measurements of blind duplicate, spike, and split samples. The inspector reviewed the results and noted that the results were within the acceptance criteria.
The laboratory continued to participate in the EPA Cross-Check Program (for drinking water)
- and the Interlaboratory Comparison Program provided by a vendor (Analytics, Inc.), and several laboratories (for example, Department of Energy (DOE) RESL and DOE EML). The quality control of environmental radioanalyses at DESEL emulated the internal process control program of NationalInstitute of Standards and Technology (NIST). DESEL's participation in these programs was excellent.
The QA officer at the laboratory conducted independent audits of laboratory operations.
The audits were methodical and provided very good insight for improvement where needed.
The laboratory published a Quality Assurance report semi-annually. The inspector reviewed
' the reports from 1996 and 1997, c.
Conclusion The contractor laboratory continued to implement excellent QA/QC programs for the REMP, and continued to provide effective validation of analytical results and the programs are capable of ensuring independent checks on the precision and accuracy of the measurements of radioactive material in environmental media.
F8-Miscellaneous Fire Protection issues F8.1 (Closed) LER 50-336/97-01:Inadeauate Fire Seal Material Installed between Some Anoendix R Fire Areas a.
Insoection Scone (9232Q)
The inspector reviewed Licensee Event Report (LER) 50-336/97-01 which concerned the.
fact that on June 21,1996, a cork material, which was combustible, was found to be
. installed between Appendix R fire areas at Unit 2.' This cork material had been installed
'during original construction as a filler material for the seismic gap openings of wall
)
interfaces. These walls were located in the Auxiliary Building and the Enclosure Building.
l The existence of combustible materialin these fire barrier walls placed the fire barriers outside the design basis of the Appendix R analysis. The inspector confirmed licensee corrective actions by reviewing documentation of licensee corrective actions and having l
discussions with personnel involved with making appropriate design changes to the system, j
- b.
Observations and Findinas l
The licensee established fire watches as temporary compensatory measure. Design Change M2-97502," Repair of Fire Barrier Expansion Joints Containing Cork", was issued on-January 14,1997. The modification consisted in removing much of the cork and replacing
~it with Dow Corning Silicone Foam which would provide a three hour fire barrier. This modification was completed on March 15,1997. The inspector reviewed a test report dated l
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107 July 15,1985, and a vendor drawing dated May 16,1985, which certified this foam as an
~
- acceptable fire barrier.
On June 5,1997, additional fire barriers were discovered which contained the cork material.
Condition Report (CR) M2-97-0949 was issued to identify this problem. A compensatory fire watch was established. This issue was checked as not reportable on the CR. The
.
inspector questioned this as it was the same as the original event. During this inspection on,
March 26,1998, the licensee re-evaluated the deportability and determined that a new LER or an update to the original LER should have been issued. This CR is still under evaluation.
The licensee stated that a new design change was being written to install new fire barrier materia!.
c.
Conclusions
-.The licensee has performed adequate corrective action for this LER. The modification
. performed will correct the fire barrier deficiency reported in the LER. - Based on corrective actions already taken and the proposed action for the cork identified in June,1997, no
_
further NRC follow-up is required. However, the failure to report the second instance of an
.
Appendix R fire barrier deficiency constitutes a violation of minor significance and is not subject to formal enforcement. LER 50-336/97-001is closed.
V. Manaaement Meetinas-X1 Exit Meeting Summary j
The inspectors presented the inspection results to members of licensee management at separate meetings in each unit ' t the conclusion of the inspection. The licensee a
- acknowledged the findings presented.
~ X1.1 Final Safety Analysis Report Review A recent discovery of a licensee operating their facility in a manner contrary to the updated final safety analysis report (UFSAR) description highlighted the need for additional
~
verification that licensees were complying with UFSAR commitments. All reactor
inspections will provide additional attention to UFSAR commitments and their incorporation l
into plant practices, procedures and parameters.
While performing the inspections which are discussed in thic report the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. An inconsistency was noted between the wording of the UFSAR and the plant practices, procedures and/or parameters observed by the inspectors, as is documented in Sections U2.03.2, U2.E8.1, and U3.03.2 of this inspection report.
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108 INSPECTION PROCEDURES USED IP 37550:
Engineering IP 37551:
Onsite Engineering IP 40500:
Licensee Self-Assessments Related to Safety issues inspections IP 42700:
Plant Procedures IP 61726:
Surveillance Observations IP 62702:
Maintenance Program IP 62703:
Maintenance Observation IP 71707:
Plant Operations IP 84750-02 Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP 92700:
Onsite follow-up of Written reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Follow-up - Plant Operations IP 92902:
Follow-up Maintenance IP 92903:
Follow-up Engineering
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109 ITEMS OPENED, CLOSED, AND DISCUSSED The followina items were opened durina this inspection:
ITEM NUMBER DESCRIPTION SECTION URI 245/98-207-01 Gas Turbine Generator 4/98 Tachometer U 1.E2.1 Failure VIO 245/98-207-02 Gas Turbine Generator Fuel U 1.E7.1 VIO 336/98-207-03 Failure to Establish Procedures for Draining U2.03.1 the Safety-Related Systems with the Exception of the RCS NCV 336/98-207-04 Tagout isolation U2.M1.2 NCV 336/98-207-05 Spill During Fill of LPSI Piping U2.M1.3 VIO 336/98-207-06 Valve 2-RB-4.1E Configuration U2.M8.1 VIO 336/98-207-07 Failure to Test the 4 Digital Liquid and U2.M8.2 Gaseous Effluent Radiation Monitors NCV 423/98-207-08 Failure to Test the 4 Digital Liquid and U2.M8.2 Gaseous Effluent Radiation Monitors NCV 336/98-207-09 Failure of 2 MSSVs to Open within Required U2.M8.3 TS Limit VIO 336/98-207-10 Failure to Provide Complete Information in U2.E8.1 9/3/97 Submittal-Fuel Oil NCV 336/98-207-11 QA - Non-QA isolation Problem for 2 U2.E8.3 Radiation Monitors URI 423/98-207-12 Diesel Generator Failure U3.03.3 URI 423/98-207-13 Commitment Tracking U3.07.2 IFl 423/98-207-14 SW Loop to PASS, SW Chlorine, Corrosion U3.M2.2 Control, AFW VIO 423/98-207-15 MEPL Program U3.M3.1 VIO 336/98-207-16 Failure to Measure Wind Speed Channels IV.R1.2 NCV 245/336/423 Failure to Review Calibration Procedures for IV.R1.2 98-207-17 Meteorological Instrumentation
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110 The followina items were updated durina this inspection:
IFl 336/94-201-90(Section U2.E8.1)
eel 336/96-201-42(Section U2.E8.2)
. eel 336/96-201-43(Section U2.E8.2)
URI 423/96-01-07(Section U3.03.2)
URI 423/98-206-05(Section U3.E7.1)
The followina items were closed durina this inspection:
URI 245/97-208-01 (Section U1.E7.1)
URI 336/97-207-03 (Section U2.M8.1) -
URI 336/423/98-206-03(Section U2.M8.2)
VIO 336/97-208-03(Section U2.E8.4)
eel 336/96-06-11 (Section U2 E8.5)
eel 336/96-08-06(Section U2.E8.5)
eel 336/96-08-08 (Section U2.E8.5)
~ eel 336/96-08-10(Section U2.E8.5)
eel 336/96-09-10(Section U2.E8.5)
eel 336/96-201-12(Section U2.E8.5)
eel 336/96-201-29(Section U2.E8.5)
eel 336/96-201-36(Section U2.E8.5)
IFl 423/97-02-16(Section U3.03.3)
eel 423/96-201-10(Section U3.08.3)
IFl 423/97-02-15(Section U3.M1.1) -
URI 423/97-203-12(Section U3.M1.3)
eel 423/96-201-34(Section U3.M2.1)
eel 423/96-201-43(Section U3.M3.1)
IFl 423/97-01-07(Section U3.M8.3)
eel 423/96-201-22(Section U3.E1.1.1)
URI 423/96-08-20(Section U3.E1.1.1)
. eel 423/96-06-13(Section U3.E2.1.1)
eel 423/97-202-09(Section U3.E2.1.1)
eel 423/96-201-15(Section U3.E2.2)
IFl 423/96-09-17 (Section U3.E2.3)
VIO 423/97-202-08(Section U3.E7.1)
,
IFl 423/94-11-09 (Section U3.E8.5)
eel 245/336/423/97-03-02(Section IV.S8.1)
IFl 245/336/423/97-207-04(Section IV.S8.2)
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111 The followina LERs were closed durina this inspection:
)
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336/97-32(Section U2.M8.3)
336/96-42 (Section U2.E.8.3)
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423/96-37 (Section U3.08.1)
l 423/97-19 (Section U3.08.2)
l 423/96-28 & 96-28-01 (Section U3.E1.1.2)
l 423/96-40 (Section U3.E1.1.3)
l 423/97-28-01 (Section U3.E2.1)
i 423/96-034-01 (Section U3.E8.1)
423/97-47 (Section U3.E8.2)
I 423/97-56(Section U3.E8.4)
336/97-01 (Section IV.F8.1)
The followino LERs were updated durina this inspection:
I 423/96-39 (Section U3.E2.1.2)
j 423/97-50(Section U3.E8.3)
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i 112 LIST OF ACRONYMS USED ACOT analog channel operational test ACR(s)
adverse condition report (s)
AITTS action item tracking and trending system AOO(s)
anticipated operational occurrence (s)-
AOP(s)
abnormal operating procedure (s)
. AOV(s)
air-operated valve (s)
ARP(s)
alarm / annunciator response procedure (s)
)
AWO(s)
automated work order (s)
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BOM bill of materials
.CCE charging pump cooling CCP-reactor plant component cooling CCPL chemical consumable product list i
CDA containment depressurization actuation l
CFR-Code of Federal Regulations
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CHS charging system CIV(s)
containment isolation valve (s)
l CMP
~ configuration management plan / project
CR(s)
condition report (s)
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. CRAB control room alarm book i
DCN(s)
design change notice (s)
DCP design change package DCR design change record
'DESEL Duke Engineering & Services Environmental Laboratory DWST demineralized water s'torage tank EDG(s)
emergency diesel generator (s)
EDI engineering department instruction EDST equipment drain storage tank l
eel (s)
escair.ted enforcement item (s)
EEQ electrical equipment qualification EOP(s)
emergency operation procedure (s)
EPIX equipment performance and information exchange
'
'EPRI
.' Electric Power Research Institute.
EQ-environmental qualification EOR (s)
equipment qualification record (s)
ESF engineered safety feature ESW -
emergency service water FAC-free available chlorine FLS first line supervisor
.FME foreign material exclusion
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FSAR Final Safety Analysis Heport FSARCR(s)
Final Safety Analysis Report Change Request (s)
' feedwater '
- FWlV(s)
feedwater isolation valve (s)
- GL-Generic Letter
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l 113 gpm gallons per minute
)
GT gas turbine GTG gas turbine generator HELB
HPSI high pressure safety injection HX heat exchanger -
ICAVP._
Independent Corrective Action Verification Program IFl inspector' follow item INPO Institute of Nuclear Power Operators
1R(s)
Inspection Reports (s)
KSREL.
key safety-related' equipment list
- LCO'
limiting condition for operation
-
LDT(s)
line designation table (s)-
LER(s)
licensee event report (s)
LOCA'
- loss of coolant accident LPSI low pressure safety injection MCC motor control center MEPL(s)
material,' equipment, and parts list (s)
MIF(s)
material issue forms (s)
MIMS materials information management system MMOD maintenance modification MOPD
. maximum operational pressure differential MOV(s)
motor-operated valve (s)
MRIR maintenance receipt inspection program i
MSARBV(s)
. main steam atmospheric relief bypass valve (s) -
mean sea level MSSV main steam safety valve NCR(s)
nonconformance report (s)
NCV non-cited violation NEAC Nuclear Engineering Advisory Council
' NGP(s)
nuclear guidance procedure (s)
NI(s)-
nuclear indicator (s)
' NIST NationalInstitute of Standards and Technology NNECO'
Northeast Nuclear Energy Company NOV(s)
' NPRDS nuclear plant reliability data system NPSH net positive suction head
NRC-Nuclear Regulatory Commission
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NRG~
nuclear receiving group -
NRR Nuclear Reactor Regulation NSIC
' Nuclear Safety Information Center NSR-nonsafety-related NUQAP-Northeast Utilities Quality Assurance Program
,
' NUREG Nuclear Regulation OCA Office of Congressional Affairs 2OD i operability determination ODCM Offsite Dose Calculation Manual
- OEDO Office of Executive Director for Operations
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m.__m.__b__
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114 OP(s)
operating procedure (s)
ORA Office of the Regional Administrator l
OSTI -
operational safety team inspection PA-protected area
' PAO-Public Affairs Office PDR-Public Document Room PEO plant equipment operator PI(s)
program indicator (s)
PMMS'
production maintenance managemer. system
-
PORC plant operation review committee PPC plant process computer PRA
_
probabilistic risk assessment i
. PTSCR(s)
proposed technical specification change request (s)
PWR pressurized water reactor QA quality assurance OAP Quality Assurance Program QSS quench spray system RAI request for additional information RBCCW reactor building closed cooling water RCC rod control center
'
RCP(s)
reactor coolant pump (s)
'
REMODCM -
Radiological Effluent Monitoring and Offsite Dose Calculation Manual I
RFO refueling outage RG Regulatory Guide RHR residual heat removal
.RHS residual heat removal system
'
RIE replacement item evaluation RPCCW reactor plant component cooling water RSS recirculation spray system RSST
. reserve station service transformer RWST refueling water storage tank SER(s)
safety evaluation report (s)
GERO
' station emergency response organization SFP spent fuel pool SGARBV(s)
steam generator atmospheric relief valve (s)
SGCS-safety grade cold shutdown i
SGTR steam generator tube rupture I
SIL significant item list SORC site operations review committee SOV(s)"
solenoid-operated valve (s)
SPO'
Special Projects Office
SPROC special procedure
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SRAS sump recirculation actuation signal SRP-Standard Review Plan SSER-supplemental safety evaluation report i
SW service water SWP plant service water
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_ _ _ _ _ _ _ _. - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ____ _ __ _ _ _ __ _ ___ _ ___ _ _ _ ___ _ _
_
115 TDAFW turbin driven auxiliary feedwater TE(s)
technical evaluation (s)
TR(s)
trouble report (s)
)
- TRM lechnical Requirements Manual l
TS(s)
technical specification (s)
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.TSCR(s)
technical specification change request (s)
UFSAR updated final safety cnalysis report UlR(s)
unresolved indication report (s)
URl(s)
unresolved item (s)
USO(s)
unresolved safety question (s)
l VETIP vendor evaluation technical information program VIO violation V/C work control YAEL Yankee Atomic Environmental Laboratory
.)
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