ML20211G012
| ML20211G012 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 09/23/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20211F998 | List: |
| References | |
| 50-443-97-04, 50-443-97-4, NUDOCS 9710010361 | |
| Download: ML20211G012 (36) | |
Text
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l U. S. NUCLEAR REGULATORY COMMISSION REGION I Docket No.:
60-443 License No.:
NPF 86 Report No.:
50-443/97 04 Licensee:
North Atlantic Energy Service Corporation Facility:
Seabrook Generating Station, Unit 1 Location:
Post Office dox 300 Seabrook, New Hampshire 03874 Dates:
June 16,1997 August 15,1997 inspectors:
F. Psul Bonnett, Senior Resident inspector (Acting)
Wililam T. Olsen, Resident inspector David M. Silk, Resident inspector Javier Brand, Resident inspector Intern John Lusher, Emergency Preparedness Specialist Approved by:
Richard J. Conte, Chief, Projects Branch 8 Division of Reactor Projects 9710010361 970923 PDR ADOCK 05000443 G-PDR c....
.J
EXECUTIVE
SUMMARY
Seabrook Generating Station, Unit 1 NRC Inspection Report 50 443/97 04 This integrated Inspe etion included aspects of licensee operations, engineering, maintenance, and plant support. The report covers an 8 week period of resident and specialist inspection.
Ooerations:
Seabrook Etation's conduct of operations was professional and focused on safety principles I.Section 01.1).
Station chemistry and operations personnel failed to exercise a questioning attitude when the refueling water storage tank (RWST) boron concentration sample results were low, net.r the Technical Specification (TS) minimum limit. This event demonstrated a willingness by station personnel to accept results close to limits (until intervention at the upper management level) and not implement corrective actions to prevent exceeding a TS limit (Section 01.2).
The control room operators demonstrated a good questioning attitude and response to minor changes in Tave during blended makeup operations. Appropriate interim corrective actions were implemented by the Operations management until a permanent fix can be installed (Section 01.3).
The limited review of deficiency tags (DT) in the Diesel Generator (DG) rooms indicates problems with the implementation of the DT process and the timeliness of corrective actions (Section O2.2).
Seabrook's staff conducted a well coordinated effort to evacuate and refill the reactor coolant system (RCS) following mid loop operations. Safety was emphasized throughout the evolution and other activities that could have potentially impacted the RCS were prohibited. Operators demonstrated a good questioning attitude and team work to evaluate RCS conditions and unexpected level changes.
Although lessons learned from the previous outage evacuation and refill evolution were incorporated, unexpected level changes occurred which indicated that further procedural refinement is necessary to control level. Engineering personnel did not perform a thorough evaluation of the impact of saturated conditions on alllevel instrumentation. (Section O2.3).
Although many procedures were revised to support startup from Cycle 6 outages, the design change records (DCR) process, used to implement the Cycle 6 core design, failed to revise two safety-related procedures on a priority basis. This resulted in the unit operating at power for 11 days with an ernergency and off-normal procedure not having updated values for rapid boration in the event that all control rods fail to fully insert on a reactor trip. This violation of NRC requirements indicates a weakness in procedure control. Further, the scope of the adverse li
condition report (ACR) for the event was initially not broad enough to prevent recurrence address, the safety impact of plant operations, and generic concerns l
with the DCR process (Section 03.1).
Deviation from the procedure to control seating safety injection system check valves occurred without proper approval as required by the TS. The process used f
did not afford a station qualified reviewer or Station Operations Review Committee (SORC) the opportunity to perform a safety review of the change in activity.
Further, the adequacy of the procedure was questionable since it did not bound the evolution with acceptance criteria for the time period for seating the check valve.
This review also brought into question the adeauncy of the procedure compliance policy that albwed these actions (Section 03.2).
Maintenance:
The engineering and maintenance staffs thoroughly assessed and resolved the issues regarding the uncontrolled loading of the diesel generator. Good coordination and oversight were demonstrated throughout the troubleshooting and evaluation efforts (Scction M1.1).
Three inadvertent feedwater isolation actuation events occurred during surveillance testing within a three week period. This indicated a trend of not properly coordinating simultaneous surveillance activities or anticipating possible integrated plant responses during unusual plant configuration. The inadvertent feedwater isolation actuation events also demonstrated an inattention by the operators to properly assess plant indications and changing plant conditions during the performance of complex evolutions (Section M1.2).
Proper design and maintenance controls and management overview were implemented to address the leaking seal table fitting. Engineering actions were conservative with good analyses. However, the wording in the engineering and work package for the clamp application was confusing on the allowed torque limits versus the actual torque required to properly seat the fitting nut. The inspector determined that the work package review was weak resulting in several torquing actions and re-review of the work package (Section M1.3).
Enaineerina:
The engineering staff performed well to determine the cause of the low indicated flow from the chemical volume and control system's makeup flow totalizer. Several attempts to correct this recurring problem with the makeup flow totalizer have occurred since the plant's initial startup. Engineering efforts to develop a permanent fix for the issue appears to be effectivs (Section E1.1).
A larger spring was installed in the nitrogen supply check valve for the accumulator during maintenance activities and was later discovered and replaced. However, the weak engineering evaluation of dissimilar components on the system engineers part lii 1
j
I created the potential for an unauthorized modification of the check valve requiring further licensee and NRC staff review (Section E1.2).
The Reactor Engineering (RE) department demonstrated good initiative by briefing e
operations personnel on the expected characteristics of the Cycle 6 core. Also, RE personnel worked closely with operations personnel during the low power physics testing. Finally, a ccre designer demonstrated that mathematical modeling characteristics caused the anomalous fluctuations in the nuclear channel factor maps at the end of cycle 5. Overall, performance in this area was very good (Section E1.3).
Station engineers demonstrated a good questioning attitude and knowledge of e
adverse flooding conditions by identifying the site barriers not considered in the Updated Final Safety Analysis Report. The actual safety consequences of this event were minimal due to the time of discovery and the implementation of prompt corrective actions. The inspector verified design control program changes to be in place and the station personnel were cognizant of the program requirements (Section E8.1).
Plant Suonort:
o The licensee continues to maintain a good emergency preparedness program. The ernergency response plan and implementing procedures were current and effectively implemented. The emergency facilities, equipment, instruments and supplies were found to be maintained in a state of readiness. All required inventories were completed. A sampling of emergency response organization personnel training records indicated that training and qualifications were current. Reports indicated that quality assurance audits were adequate and that they satisfied 10CFR50.54(t) requirements, iv
TABLE OF CONTENTS E X EC UTIV E S U M M ARY............................................. ll T ABLE OF CO NTENTS.............................................. v
- 1. Operations
.................................................... 1 01 Conduct of Operations.................................... 1 01.1 General Comments (71707)........................... 1 01.2 Low Boron Concentration in the Refueling Water Storage Tank.. 1 01.3 Minor Reactor Power increase During Blended Makeup Activity.. 3 02 Operational Status of Facilities and Equipment................... 3 02.1 Routine Pla nt Tours................................. 3 02.2 Diesel Generator Room Deficiency Tags................... 4 02.3 Mid Loop Operations................................ 4 03 Operations Procedures and Documentation 6
03.1 Safety Related Procedures Revision...................... 6 03.2 Seating of Accumulator Check Valves.................... 7 07 Quality Assurance in Operations............................ 10 07.1 Technical and Safety Reviews 10 08 Miscellaneous Operations issues............................ 10 08.1 Licensee Event Report Review 10 08.2 (Closed) LER 50 443/96 004 01 and VIO 50 443/96-010-02:
Emergency Feedwater System Valve Closure.
10
- 11. Maintenance
................................................. 11 tM1 Conduct of Maintenance
................................. 11 M1.1 Diesel Generator Malfunction During Maintenance Run....... 11 M1.2 Inadvertent Feedwater Isolations During Surveillance Testing 12 M1.3 Seal Table Leaking Tee Fitting
........................ 13 111. E ngin e e ring.................................................. 15 E1 Conduct of Engineering
.................................. 15 E1.1 Blended Makeup Flow Totalizer........................ 15 E1.2 De s ig n Ch a ng e................................... 16 E1.3 Reactor Engineer Startup Activities..................... 17 E8 Miscellaneous Engineering issues...........................
18 E8.1 (Closed) LER 50 443/97-001 00: Seabrook Station Design Basis Flooding Analysis............................. 18 IV. Plant Support
................................................ 19 R8 Miscellaneous RP&C lssues 19 R8.1 (Closed) LER 50-443/97-005-01 and URI 97-02 01:
Misposition of Main Steam Line Radiation Monitors.......... 19 R8.2 (Closed) LER 50-443/96 009-01: Missed Surveillance Primary Closed Cooling Water Rate of Change Monitor Alarm......... 20 v
I Table of Contents S8 Miscellaneous Security issues.............................. 20 S8.1 (Closed) VIO 97 02 03, Failure To Control Licensee Designated Vehicles as per Security Plan Hequirements............... 20 S8.2 (Closed) VIO 97 03 08, Designated Vehicle Left Unattended With Keys in Ignition and Running...................... 20 S8.3 (Closed) LER 50-443/97 S01-00: Loss of Duty Firefighter Keys. 21 P1 Emergency Preparedness (EP).............................. 21 P2 Status of EP Facilities, Equipment, and Resources 21 P3 EP Procedures and Documentation.......................... 22 P4 Staff Knowledge and Performance in EP...................... 23 P5 Staf f Training and Qualification in EP......................... 24 P6 EP Organization and Administration.......................... 24 P7 Quality Assurance in EP Activities........................... 25 V. Management Meetings.........
26 X1 Exit Meeting Summ ary................................... 26 PARTI AL LIST OF PERSONS CONTACTED............................... 27 INSPECTIO N PROCEDURES USED..................................... 28 LIST O F AC RONYMS U S ED......................................... 30 vi i
Report Details Summarv of Plant Status Seabrook Station began this inspection period shutdown for the fifth refueling outage (OR05) which continued since May 10. At the conclusion of the outape, the operators raised the primary plant to normal operating pressure and temperature in preparation for making the reactor critical. Operators made the reactor critical on June 26, and synchronized the main turbine generator to the grid on June 28. The unit reached 100%
power on July 3. On July 3, after a weekly chemistry sample determined that the boric acid concentration in the refueling water storage tank (RWST) was below the Technical Specification (TS) Lirniting Condition for Operation (LCO), control room operators initiated a controlled plant shutdown, lowering power to 91% prior to restoring the RWST boron concentration to the required amount and exiting the TS LCO. The unit was returned to 100% and has remained essentially at full power for the remainder of the period, with minor power reductions to support instrument calibrations and turbine valve testing.
Two 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notifications for dead seals found on the plant circulating water traveling screens occurred on July 20 and 27. The operations staff notified the NRC via the emergency notification system in accordance with Section 4.1, of the Plant Environmental Protection Plan.
- l. Operations 01 Conduct of Operations 01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted icequent reviews of ongoing plant operations, in general, Seabrook Station's conduct of operations was professional and focused on safety principles with some exceptions as noted in the following paragraphs.
01.2 Low Boron Concentration in the Refueling Water Storage Tank a.
insoection Scope (71707)
On July 3, the s!.;ft manager declared the RWST inoperable and began a plant shutdown after weekly chemistry results indicated that the RWST boric acid concentration was below the TS LCO. The unit was operating at 100% power when the event occurred. The shift manager notified the NRC of the shutdown in accordance with 10 CFR 50.72(b)(1)(A). The inspector reviewed the circumstances and rcot cause evaluation for this event.
b.
Observations and Findinas
- A chemistry technician informed the control room supervisor (CRS) that the RWST boron concentration was 2696 parts per million (ppm). The low boron concentration was confirmed by a second sample. The TS LCO requirement for the RWST with a boron concentration less than 2700 ppm is that the boron concentration be restored within one hour, or that the unit be in hot standby within the next six hours and in cold shutdown
2 within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. The CRS directed a controlled plant shutdown and operators lowered power to 91% prior to restoring RWST boron concentration to the proper amount and exiting the TS LCO.
While the operators were reducing reactor power, chemistry technicians conducted two controlled boric acid additions to the RWST. The technicians verified that the boron concentration was greater than 2700 ppm (between 2719 and 2746) by obtaining four consecutive FiWST samples. After confirming RWST operability, the CRS exited the TS LCO and returned reactor power to 100E The CRS Initiated an adverse condition report (ACR 971749) to evaluate the event.
The inspector noted that the results of the two weekly samples taken prior to the event sample were 2717 ppm (June 26) and 2702 ppm (June 22). Tho inspector questioned if an administrative limit had been established or if additional measures were implemented when the sample results were close to the TS minimum limit, such as: increasing the sampling frequency, recirculating the RWST, or adding boric acid. The inspector noted that no licensee actions had been takan. However, during a morning managers meeting on July 18, when the reactor engineer announced that the results of the weekly RWST sample was 2705 ppm (a difference of 20 ppm from the previous week sample) the Station Director gave direction to increase the boron level. RWST boron concentration was then raised to 2800 ppm.
As a result of this and two other recent boron anomalies (ACRs 971716 and 97-1745),
the Management Review Team (MRT) established a Root Cause Team (RCT) to collectively analyze the boron events and determine the root causes. For this event, the team determined that the root causes was inadequate attention to an emerging problem and failure to makeup to the RWST following the June 22 sample. A contributing f actor was the failure to consider affects of tank stratification and boron analysis accuracy.
The RCT recommended that an administrative range above the TS range be established for the RWST boron concentration. Exceeding the administrative limits would initiate a closer analysis of boron concentrations, analysis accuracy, and possible effects of tank stratification. The MRT and Station Operations Review Committee (SORC) accepted the corrective action which will be implemented in the near future.
c.
Conclusion Station chemistry and operations personnel failed to exercise a questioning attitude when the RWST boron concentration sample results were low, near the TS LCO. This event demonstrated a willingness by station personnel to accept results close to limits (until intervention at an upper management level) and not implement corrective actions to prevent exceeding a TS limit.
4 3
i 01.3 Minor Reactor Power increase During Blended Makeup Activity a.
Insoection Scone (71707)
On July 13, a minor reactor power increase transient occurred when control room operators conducted a 600 gallon blended makeup to the reactor coolant system (RCS).
The inspector reviewed the event and discussed interim corrective actions with Operations management.
b.
Observations and Findinas The control room operators noted and questioned minor Tave changes following the makeup operation. The operators subsequently determined that about 670 gallons had been added to the RCS, and that the additional volume was reactor makeup water (RMW).
The CRS directed that fifteen gallons of boric acid be added to compensate for the RMW overshoot.
Engineering determined that flow errors in the total makeup flow totalizer, CS FK 111, was the cause for the excessive makeup and developed a strategy to correct the problem (details of the engineering activities are discussed in Section El.2). Until the corrective actions are completed, Operations management issued a Standing Operating Order (SOO) to emphasizo that boric acid makeup to the RCS be performed according to procedure OS1008.01, Chemical Volume and Control System Makeup Operations. This ensures that operators monitor volume control tank (VCT) levei tor correct level changes, monitor the boric acid totalizer for proper boric acid addition and monitor RCS temperature to ensure an appropriate makeup had been made.
The inspector discussed the SOO with several members of the operations staff..They demonstrated an adequate knowledge and understanding of the problem and interim corrective action. Plant operations in accordance with the SOO will continue until a modification can be installed in September 1997.
c.
Conclusions The control room operators demonstrated a good questioning attitude and response to minor changes in Tave during blended makeup operations. Appropriate interim corrective actions were implemented by the Operations department management until a permanent fix can be installed.
02 Operational Status of Facilities and Equipment 02.1 Routine Plant Tours (71707)
The inspectors used Procedure 71707 to perform routine tours of the facility and also to walkdown accessible portions of engineered safety feature (ESF) systems:
e Safety injection (SI) System e-l Emergency Feedwater (EFW) System e
Diesel Generators (DG)
4 4
Equipment operability, material condition, and housekeeping were acceptable in all cases.
Several minor discrepencies were brought to management's attention and were corrected.
The inspectors identified no substantive concerns as a result of these walkdowns.
02.2 Diesel Generator Room Deficiency Tags a.
Insoection Scooe (71707)
During the tour of both DG rooms, the inspector noted what seemed to be an excessive number of deficiency tags on system equipment, b.
Observations and Findinas The inspector made a detailed listing of 22 deficiency tags (DTs) in both DG rooms. The older tags were numbered with a different number th'.n the DT assigned number and six of the DTs were undated. Working with operations personnel, the inspector confirmed that all but four of the DTs had active work requests W initiated. During a followup review outside the inspection period, the remaining four WRs were reviewed. However, the issue of the adequacy of the implementation and timeliness of corrective actions of the DT process is unresolved pending further NRC staff review. (URI 50 443/97-04 01) c, Conclusions The limited review of deficiency tags in the DG rooms indicated potential problems with the implementation of the DT process and the timeliness of corrective actions. This issue will receive further review by NRC staff.
02.3 Mid Loop Operations a.
Insoection Scope (71707)
On June 18, activities commenced for mid-loop operations following core refueling and reactor vessel reassembly. The inspector reviewed procedures, attended briefings, and observed procedural implementation regarding the RCS evacuation and fill evolution.
b.
Observations and Findinas The inspector determined that pre evolution activities were thorough. The inspector observed the pre job briefing which focused the personnel participating in the evolution on their responsibilities and the safety significance of the evolution. Management emphasized the importance of monitoring RCS levels and residual heat removal (RHR) flow rates to prevent vortexing (or cavitation) of the RHR pumps throughout the duration of the evolution. Operators reviewed and prepared to implement the abnormal procedure for a a
loss of shutdown cooling since that event would be the greatest threat to reactor safety.
Other precautions, such as stationing individuals near the RHR pumps to listen for symptoms of cavitation and at the sight glass (tygon tubing) in containment to monitor level and maintain its condition, were also implemented. Overall, a good awareness and
5 control of plant activities, which could impact the RCS during this evolution, were maintained.
Operators maintained good control of RHR flows and RCS level during the drain-down. The operators began lowering RCS level from about -29" below the reactor vessel flange to
-73"in order to remove the steam generator (SG) nozzle dams using operating procedure OS1000,14, Reactor Coolant System Evacuation and Fill. After removing the nozzle dams and installing the associated SG manways, level was lowered further to 85" to commence the evacuation portion of the evolution. Operators reduced RHR flow to 1250 gpm to prevent pump cavitation. The inspector verified that RHR flow was within the designated limit and that RCS levelindicators tracked within two inches of one another d ring the drain-down as requi ad by the procedure.
During the drr:n-down to 85", the ultrasonic detector on Loop 4 became Inoperable. The CRS stopp',d the drain-down per procedure to assess the situation. Four instruments were used to monitor RCS level: two ultrasonic detectors located on the bottom of RCS Hot Leg Loops 1 and 4, RC Ll9405 attached to the bottom of the Loop 1 Crossover Leg, and the sight glass attached to the bottom of the Loop 3 Crossover Leg. The operators determined that the drain-down could be continued safely without the Loop 4 indicator due to the consistent performance of the three remaining levelindications.
During RCS refill activities, in unexpected change in reactor level from 54" to 70" occurred. Operators noticed snght !cvel oscillations and that level was increasing at a rate not commensurate with charging flow when reactor levelinitially reached -70" (Just above the top of the RCS hot leg piping). The CRS determined that inventory moving back and forth from the SG U-tubes and the pressurizer (PZR) due to slight pressure differences between these spaces caused the oscillations. Once the SG U tubes could no longer communicate with the PZR and vessel head, less volume existed from which to draw a vacuuta. Vacuum increased in the PZR and vessel head which was drawing inventory up into those spaces. To stabilize the level oscillations, operators decreased the vacuum in the PZR which rasulted in the unexpected level drop. Operators stabilized plant conditions and evaluated the phenomena. The level dropped because of RCS inventory displacing entrapped air in the SG U tubes that had vented when vacuum decreased. RCS fill activities were then continued without further incident. The core remained covered ( 135" top of core) throughout the event and cavitation did not occur in the RHR pumps. The inspector noted that these oscillations were an unexpected challenge to the operators and Operations management will be incorporating the lessons-learned into the next procedure revision.
During refill activities, technicians observed gas bubbles in the sight glass. The RCS was at a saturated condition of 140'F, and a pressure of about 3 psia, which caused gases to come out of solution. The inspector questioned if the levelinstrumentation had been evaluated to function properly in that kind of an environment. The instruments were evaluated for potential damage caused by the vacuum and effects of containment atmosphere on sensing line for RC-Ll0405. However, no evaluation had been performed for gases coming out of solution in the sensing line for RC-Ll9405 or in the sight glass tubing. The inspector determined that the technical and safety review was not comprehmsive in encompassing all technical aspects of the level indication. The inspector
6 did not observe any significant change in reactor level due to the affects of gassing.
Engineering personnel plan to evaluate this level detection process to identify lessons
- learned, c.
Conclusions Seabrook's staff conducted a well coordinated effort to evacuate and refill the RCS following mid loop operations. Safety principles were emphasized throughout the evolution and other activities that could have potentially impacted the RCS were prohibited.
Operators demonstrated a good questioning attitude and team work to evaluate RCS conditions and unexpected level changes. Although lessons learned from the previous outage evacuation and refill evolution were incorporated, unexpected level changes occurred which indicated that further procedural refinement is necessary to control level.
Engineering personnel did not perform a comprehensive technical evaluation of the impact of saturated conditions on alllevelinstrumentation.
03 Operations Procedures and Documentation 03.1 Safety Related Procedures Revision a.
Insoection Scone (71707)
On July 8, the Emergency Operating Procedure Coordinator performing an annual emergency procedure setpoint review, identified two safety related procedures that were not revised (as per North Atlantic Design Control Manual, Chapter 3, Design Changes), to incorporate the new Cycle 6 boron concentrations required to be injected in the event that more than one control rod failed to fully insert into the reactor core during a reactor trip.
The deficient procedures were emergency procedure, ES-0.1, Reactor Trip Response, and off normal procedure OS1202.04, Rapid Boration. As a result of the omission, the plant operated for 11 days, since the start of Cycle 6 on June 27, with non conservative boron values in these procedures. The inspector reviewed the applicable documents and discussed the issue with the several Engineering and Operations Departments personnel, b.
Observations and Findinas Following the discovery of this issue, the operations management determined that the operators had not been informed of the new values prior to plant startup. Management initiated ACR 971767 to review the issue and implement immediate corrective actions for upgrading the procedutes and informing the operators of the new boron values. These actions were completed by July 11.
The emergency procedure, ES 0.1, directs the operator to rapidly borate a specific quantity of boron for each control rod that does not fully insert on a reactor trip. If the action can not be established, ES 0.1 refers the operator to the off normal procedure for rapid boration. The bases for the specific amount of boron is to insure that a sufficient shutdown margin exists that will preclude an inadvertent criticality in a cold shutdown condition. Due to these values increasing for the Cycle 6 Core design and the procedures
l 7
not being upgraded to reflect the new values, the two safety-related procedures were non-conservative.
The inspector determined that design change record (DCR #96 020), which incorporated the Cycle 6 core design, failed to identify the procedures as needing to be updated. The DCR should have identified and upgraded the procedures through an interdisciplinary review process. Technical Specification 6.7.1.a specifies that written procedures recommended in Appendix A of Reguletory Guide 1.33, be maintained. The failure to update (or maintain) these two proceJures by the end of the refueling outage and the operation of the unit for 11 days with procedures with outdated values is a violation of the TS. (VIO 60 443/97 04 02)
The inspector raised concerns regarding the MRT and the Operations Departments' dispositioning of the ACR. The MRT failed to properly evaluate other significant implications, such as: 1) the safety significance and impact of having operated for 11 days with a non-conservative required boron value to compensate for a stuck rod event; and 2) to evaluate the existing DCR process for generic implications with their interdisciplinary review practices to determine why it failed to recognize which procedures were affected and needed to be revised. Management agreed with the inspector's concerns, and revised the original scope of the ACR to require an engineering evaluation of these issues. The ACR did identify the need to ensure that a sufficient review be performed for future new core designs.
c.
Conclusions Although many procedures were revised to support startup from the Cycle 6 outage, the design change process, used to implement the Cycle 6 core design, f ailed to identify and revise two safety-related proceoures on a priority basis. This resulted in the unit operating at power for 11 days with an emergency and off normal procedure having outdated values for rapid boration in :he event that all control rods f all to fully insert on a reactor trip. This violation of NRC requirements indicates a weakness in procedure control. Further, the scope of the ACR initiated for the event was initially not broad enough to prevent recurrence.
03.2 Seating of Accumulator Check Valves a.
Insoection Scope (71707)
On August 8, the safety injection (SI) system was aligned in a test configuration to attempt to seat the Si to RCS loop 4 cold leg injection check valve (St V130). Specifically, the Si pump to RCS cold leg test header isolation valve (SI-V131) was left open with the test header aligned to the RWST. The inspector questioned why the test header was aligned to the RWST when operations procedure, OS1005.05, Safety injection System Operation.
directed the operators to align the test header to the primary drain tank (PDT). The inspector reviewed the operator logs and the operations procedure, and discussed the issue with Operations management. Further, the inspector reviewed the inter system relationship of the Si check valve seating evolution and its affects on containment integrity, and check valvo operability.
8 b.
Observations and Findinas l
The operators noted on June 26, that pressure at the SI pump t.
- harge header was indicating 030 psig. The source of the pressure was from the "L Accumulator through the accumulator t heck valve (SI V51) and SI V130. The SI pump discharge header with check valve SI V130 taps into the accumulator header between SI V51 and SI V50. The shift manager's turn-over sheet stated that the check valves needed to be seated, but they decided to contbue to monitor the leakage. The inspector also noted that inleakage to the "D" Accumulator throughout the month of July was at a rate of 3 to 4 gallons per day (gpd) through SI V51. The operators maintained the accumulator within the BORON concentration and levellimits of the TS, and drained and sampled the accumulator when required.
The system engineer, working with the control room staff using operations procedure OS1005.05, attempted unsuccessfully to seat check valves (SI V51 and SI V130) on July 18 and July 28. Several sections in procedure OS1005.05 address seating accumulator check valves. Section 6.2 aligns the Sl pump discharge to the accumulator fill header to epply pressure at the downstream side of the check valve (Sl V51 and SI V130). Section 6.8 addresses seating the accumulator check valve (SI V51) and Section 6.13 addresses r
seating the Si to RCS cold leg injection check valves (SI V130) using the Si test header.
All three sections of this procedure are used in this evolution and all three sections direct the test header to be aligned to the PDT, which has radiation monitoring instruments to monitor for the discharging of high activity water.
A third attempt on August 6 seated the "D" Accumulator check valve (SI V51), but not the SI V130. Specifically, when the operators returned the SI system to it's normal configuration, pressure at the SI pump discharge header continued to increase (above 1000 psig), after which the CRS directed the operators to reopen SI V131 to vent the pressure to the PDT. The shift manager and system engineer stated that SI V131 was reopened because the high pressure would lift the SI pump discharge header relief valves at 1750 psig. Furthor, since the SI V130 had not seated and the SI system would remain aligned with the SI V131 valve open to create a sufficient differential pressure across the SI V130 to seat it.
The inspector observed on August 8, that the SI system was still aligned as left above on August 6. The inspector also observed that the OS procedure had been put "on-hold" at step 6.13.5, which states " Monitor PDT and RWST levels for a minimum of 30 minutes, then perform step 6.13.6." The inspector questioned whether leaving the system in this configuration was a test or experiment requiring a safety review, since SI-V130 had not seated and high pressure could still be sensed at the Si pump discharge header with SI-V131 closed. Due to the inspectors concerns the system engineer and control room operator refloated (unseated) the accumulator check valve (SI VS1) to allow the test header isolation valve (SI V131) to be shut.
Also, North Atlantic Procedure Administration (NAPA) 3.2 states in Section 1.9, inadequate or Unexpected Results, that if it appears that the procedure is inadequate or does not yield the expected results while executing a work activity, the work shall be stopped, the system placed in a safe condition, and the cause determined, in this case,
1 9
the inspector noted, the evolution continued fcr two days with the potential of extending through the weekend and the SI V130 hed not seated by this time. The inspectors concluded that implementation of the procedure and NAPA 3.2, Section 1.9, were weak with an indefinite time to be "on hold" for the process. The system engineer responded that it is difficult to know the reason that a check valve is not fully seated with so many check valves from many flow paths tying into the Slinjection header. Even the running of the S! pump for its surveillance can unseat a check valve and cause this situation.
The inspector later noted that the tett header was aligned to the RWST, which was not in accordance with the procedure. When asked how the system lineup was changed, the shift manager stated that he directed the test lieader return to be lined-up to the RWST to prevent gravity draining the RWST through the Si pump to the PDT (as stated in a procedure caution).
NAPA 3.2, Section 3.2 Procedure Compliance, states that a first line supervisor can authorize deviation from an approved written procedure when a task requires it. This authorization, however, is in conflict with TS 6.7.5 which allows TS required procedures to be changed prie to a St stion Qualified Reviewer or SORC review provided, the intent was not changed, ant the c' ange was approved by two members of the plant management, at least one of wia n holc's a Senior Operator license. The inspector determined that the action to deviate M Nst header lineup was a change in the intent of the procedure and should have been changed per the requirements of TS 6.7.5. (VIO 50 443/97-04 03)
The inspector determined that the procedure control process had been bypassed and did not afford engineering support the opportunity to consider the impact of the procedure change on several areas, including, containment integrity, an unmonitored gaseous release path, and compliance with the Updated Final Safety Analysis Report (UFSAR). The inspector concluded that the SI V130 was operable based on the amount of leakage through the valve being within the acceptable limits specified in the Technical Requirements Manual and inservice test program. Two valve protection was always maintained, therefore, there was no RCS leakage or pressure boundary issue and primary containment integrity was maintained. Further, the inspector was shown that the use of the Si test header was bounded in the UFSAR, but the inspector remained concerned about the seemingly unlimited time frame during which the test header could be in use.
c.
Conclusions Deviation from the procedure to control seating Si system check valves occurred without proper approval as required by the TS. The process used did not afford a station qualified reviewer or SORC the opportunity to perform a nfuty review of the change in activity.
Further, the adequacy cf the procedure w2s quastionablo since it did not bound the evolution with acceptance criteria for time period for seating of the check valve. This review also brought into qu3stion the aduquacy of the NAPA 3.2 that allowed these actions.
)
v
i 10 07 Quality Assurance in Operations
-07.1 Technical and Safety Reviews (71707)
During the inspection period, the inspectors reviewed or attended multiple self assessment activities, including:
various Station Operational Review Committee (SORC) meetings and meeting o
minutes; various Management Review Team (MRT) meetings and adverse condition reports e
(ACRs).-
The SORC reviewed several activities related to safe station operation. The members of SORC actively participated in the meeting with open discussions on the plant issues while maintaining a focus on safety principles. An exception to this generally good performance was noted in the review of a work request scope change package to repair an non isolable leak at the seal table (see Section M1.3). The inspectors concluded that the self.
assessment activities were generally effective.
08 Miscellaneous Operations issues 08.1 Licensee Event Report Review The following events were reviewed in inspection report 50 443/97 03. The LERs met the requirements of 10 CFR 50.73, and the inspectors had no further questions regarding the event.
e (Closed) LER 50-443/97 012 00: Reactor Trip and ESF Actuation on Lo Lo Steam l
Generator Level, e
(Closed) LER 50-443/97 011-00: Containment Building Spray Sump Encapsulations.
e (Closed) LER 50 443/97 009-00: Degraded Fuel Rods identified in Westinghouse Fuel Assemblies.
e (Closed) LER 50-443/97 008 00: Automatic React-Trip and Feedwater Isolation.
08.2 (Closed) LER 50-443/96-004 01 and VIO 50 443/96-010 02: Emergency Feedwater System Valve Closure.
This LER was a supplement to an issue that was discussed in inspection Report 50-443/0610 (and attached Notice of Violation). This supplement documented the completed corrective actions for identified programmatic weakness in the procedure revision process and 10CFR 50.59 screening documentation. The 10CFR 50.59 screening evaluation procedure is being revised to provide additional guidance to station personnel that perform 10CFR 50.59 applicability evaluations for revisions that involve intent changes to manuals and procedures. This revision will also require that the conclusions for 10CFR 50.59 applicability be supported by a written basis, and include a review of applicable UFSAR
11 chapters and related engineering documents. A requirement also to be added to each 10CFR 50.59 evaluation is to determine whether the UFSAR requires updating to reflect the effects of the proposed change, test or experiment. The inspector reviewed the completed licensee corrective actions for the identified discrepancies and determined that they were appropriate. As a continuing corrective action, the station initiated a special 10CFR 50.59 team to review the process and make recommendations for future changes.
- 11. Maintenance M1 Conduct of Maintenance M1.1 Diesel Generator Malfunction During Maintenance Run a.
insoection Scone During OR05, on June 15, while running diesel generator (DG) 1 A in a loaded condition, load increased uncontrollably. Operators promptly shutdown the DG and system engineers evaluated the event, ultimately finding loose wires in the electronic governor. The inspector observed portions of the troubleshooting activities related to the abnormal DG performance, b.
Observations and Findinas The system engineer evaluated the situation and initially concluded that the abnormal performance was attributable to a malfunction of either the fuel pumps or the mechanical governor. The engineer developed a methodical test plan to conduct a test run of the DG to identify the malfunction. The system engineer conducted the pre test briefing with approximately 20 individuals, who were given specific observation assignments to be monitored during the test run of the DG in a loaded condition. The briefing was thorough with appropriate emphasis on safety and a good exchange of questions and answers between the observers and the system engineer. An operations shift manager was present for the briefing and during the test.
During the test run, the DG functioned normally without any unusual symptoms during load changes. However, after shutting down and subsequently restarting the DG, it immediately tripped on overspeed. Further investigation revealed two loose screws on the -
electronic governor output. Maintenance technicians tightened the screws, after which the
-DG was run successfully. The system engineer attributed the cause of the loose screws to
-installation or removal'of test equipment leads during maintenance or troubleshooting activities. Technicians checked for a similar condition on 1DG 1B, and no loose screws were found.
In addition to attempting to identify the cause of the load changes, observers were monitoring lube oil temperature to assess the effectiveness of maintenance on the temperature control valve (TCV)_that controls cooling flow through the lube oil heat exchanger. The lube oil temperature during the DG run was acceptable, but higher than normal. Engineers and technicians inspected and adjusted the TCV to control tube oil l
. _ _ _ _ l
12 temperature as required. The engineers discussed with the vendor a feature of the TCV design (a gasket) and adjustments to a lock nut to resolve the temperature control issue.
After making repairs to DG 1 A, the operators ran the DG for a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> break in and endurance run. No further problems were identified and the shift management declared the DG operable, c.
Conclusions The engineering and malntenance staffs thoroughly assessed and resolved the issues regarding the uncontrolled loading of the DG. Good coordination and oversight were demonstrated throughout the troubleshooting and evaluation efforts.
M1.2 Inadvertent Feedwater Isolations During Surveillance Testing a.
Insoection Scone During OR05, several inadvertent feedwater isolation (FWI) actuation events occurred during surveillance testing. The first event occurred on June 13 when the "C" SG was inadvertently dralned down (see inspection Report 50 443/97 03), the second occurrence was June 17 during a Solid State Protection System (SSPS) surveillance test (ST), and the third occurrence was June 25 during a turbine driven emergency feedwater (TDEFW) pump ST. The inspector observed the pre-test briefings, portions of activities in the control room and in the plant, and overall coordination of the evolutions, b.
Observations and Findinas June 17 Event l&C technicians were performing testing in the SSPS which required the reactor trip and reactor trip bypass breakers to be racked in and closed. Prior to conducting the test, the reactor trip and reactor trip bypass breakers were in the disconnect position with the FWI function bypassed. The FWI actuation occurs when permissive P-4 is activated by the opening of the reactor trip breakers and Tavg is less than 557'F. Upon completing the SSPS testing, operators racked out the reactor trip breakers to the disconnect position, resetting P 4 and inadvertently causing a FWI actuation signal, in troubleshooting the event, several attempts to repeat the resetting of P 4 by racking out the breakers produced inconsistent results. This test is normally performed at power (Tavg greater than 557'F) and would not produce a FWI actuation signal if the P-4 signal was generated.
An ACR was initiated to evaluate and to perform a root cause analysis of this FWI actuation, as well as the June 25 event and the June 13 event.
June 25 Event The inspector observed the performance of several tests including: EX1804.02, Emergency Feedwater Turbine Pump 18 Month Auto Actuation Surveillance; OX1436.02, Turbine Driven Emergency Feedwater Pump Quarterly and 18 Month Surveillance Test, and
)
13 Monthly Valve Alignment; and OX1436.13, Turbine Driven Emergency Feedwater Pump Post Cold Shutdown or Post Maintenance Surveillance. The plant was in Mode 3 with RCS temperature at approximately 558'F.
During the performance of OX1436.02, a FWI actuation occurred. The reactor trip breakers were open with the FWI signal blocked for the current condition of the plant. The FWI signal became unblocked when l&C technicians were performing cross calibration checks of the RCS temperature instrumentation. The technicians introduced a signal of greater than 564'F into the circuitry which reset the Lo Tavg input. Prior to the FW1 actuation signal, the actual RCS temperature was at 558'F. The FWI actuation signal occurred when the TDEFW pump started and drew steam from the SGs resulting in lowering RCS temperature to below the 557'F setpoint.
These two testing activities had not been performed simultaneously in the past. Neither test procedure contained a caution regarding a possible FWI actuation signal. Operators had brief indication in the control room that FWI had reset, but did not anticipate its occurrence given the plant status and activities in progress. The inspector raised a concern that this had been the third inadvertent automatic system actuation within three weeks and indicative of a deficiency in properly coordination of complex activities.
The inspector determined that the briefings for all of the observed STs covered the scope of the surveillances, emphasized actions to be taken in the event of an actual EFW actuation signal, and adequately explained individual assignments. Coordination between operations and the surveillance personnel was generally good Performance of the surveillance progressed smoothly and the surveillances were completed satisfactorily.
Operation personnel alertly cautioned the surveillance team about inadvertently initiating a safety injection signal from low steam generator pressure caused by running the TDEFW pump for an extended period during the current plant conditions, c.
Conclusions Three inadvertent FWI actuation events occurred during surveillance testing within a three week period. This indicated a trend of not properly coordinating simultaneous surveillance activities or anticipating possible integrated plant responses during unusual plant configurations. The inadvertent FWI actuation events also demonstrated an inattention by the operators to properly assess plant indications and changing plant conditions during the performance of complex evolutions.
M1.3 Seal Table Leaking Tee Fitting a,
lospection Scone On June 24 with the plant in Mode 4 and at normal operating pressure (2235 psig), a non-isolable leak was identified on the seal table at location D3. The leakage was at a tee fitting on a Swagolok plug. This tee fitting, used to backflush the incore detector strings before pulling the detectors prior to defueling, had not previously been a point of leakage.
Inspection activities included review of procedure RES95-043, Mechanical Connections for Incore Instrumentation Thimbles, the work request (WR 97WOOO405) with the 10 CFR
14 50.59 evaluation, incore Seal Table, the WR Scope Change (97WOOO405) with the revised 10 CFR 50.59 evaluation, attendance at two maintenance meetings and at the SORC meeting on June 25, and physical inspections of the seal table. The inspectors closely followed this leak repair as the last major activity of the refueling outage prior to entry into Mode 3.
b.
Observations and Findinas An l&C technician discovered the leak, while performing a routine leak inspection of the incore detector seal table after re assembly, in accordance w!th station requirements. The seal table re assembly work package authorized l&C technicians to apply torque up to 50 foot pounds (ft-lbs) to the fitting nut to attempt to stop any leaks identified. When the technician had applied 40 ft lbs to the fitting nut, the leak got worse leaking at a rate of %
pint per minute. The l&C supervisor being aware that the leak was non-isolable, stopped all further work. About four hours later,l&C technicians reinspected the seal table and noted the D3 fitting leak had decreased to approximately 10 drops per minute. The fitting manufacturer provided information that the maximum allowable torque for this fitting was 80 f t-lbs.
In a special review meeting, a plant technical support engineer presented several options to stop the leak. The selec'.cd option was to design, prepare and install a clamp to prevent the plug from being released if the fitting nut were to fait during the additional torquing process. The design included a calculation (C S 145331) to ensure that the maximum torque of 80 ft-lbs was not exceeded. This calculation which took in consideration the clamp, determined that a maximum torque of 15 ft lbs could be applied to the clamp, and that up to 23 ft lbs could be applied to the fitting nut, to obtain the desired seating of the fitting and still be under the maximum allowable torque of 80 ft lbs. The licensee conservatively choose 20 ft lbs of torque to the fitting nut. The original intention was to remove the clamp after the leak had stopped.
On June 25,1997, during a SORC meeting independently reviewed and approved the proposed installation. Technicians installed the specially designed clamp and tightened it to 14 ft lbs stopping the leak. The fitting nut was torqued to the desired 20 ft Ibs, but no movement was observed. The licensee believed that the fitting nut did not move possibly because of galling of the nut threada, or because the 20 ft Ibs should have been added to the original torque already applied. Subsequently, during removal of the clamp, the leak returned. Technicians retorqued the clamp back to 15 ft lbs and the leak was nearly stopped (less than 1 drop in 12 minutes). Subsequent leak inspections have confirmed that the leak had stopped fully. There was a problem with the clarity of the work instruction for the fitting torque settings.
Another special SORC review meeting was held, and a decision was made to perform a safety evaluation to leave the clamp in place. This evaluation was documented under Temporary Modification 97 TMOD-0025, and approved on June 26. Daily leak inspections continued for several days up to Mode 1, power operation.
l 15 c.
Conclusions Proper design and maintenance controls and management overview were implemented to address the leaking seal table fitting. Engineering actions were conservative with good analyses. However, the wording in the engineering and work package for the clamp application was confusing on the allowed torque limits versus the actual torque required to properly seat the fitting nut. The inspector determined that the work package review was weak resulting in several torquing actions and re-review of the work package.
Ill. Enaineerina E1 Conduct of Engineering E 1.1 Blended Makeup Flow Totalizer a.
Insoection Scooe (37551)
The inspector reviewed the engineering efforts to address concerns operators raised regarding the blended makeup totalizer (see Section 01.4). The operation of the blended flow loop since startup from OROS has demonstrated that the flow transmitter (CS FT-111) indicates a lower flowrate than the actual flowrate through the blend flow path. The inspector reviewed the engineering evaluation and the design change package, and discussed the issue with various engineering personnel, b.
Observations and Findinas The indicated flowrate from the blended makeup totalizer in the chemical volume and control (CS) system has been lower than the actual flowrate through the blended flow path. Flow transmitter (CS-FT-111) n aasures the total reactor makeup water (RMW) and boric acid blended flow from the mixing tee (CS MM 1). Flow from the mixer can be provided to the VCT, the spent fuel pool, the cesium removal ion exchangers, the RWST or the CS pump suctions. During makeup operatione to tN VCT, indicated changes in VCT level did not agree with the change in the total number of gallons indicated on the blended flow totalizer. This hs resulted in more total RMW be.ng added to the VCT than anticipated for a ds' smount of boric acid.
The flow transmitter.J FT-111) has undergone two modificauons since initial startup.
During OR02, CS FT 111 was replaced with an ultrasonic flow meter due to the recurring gas buildup in the original FT's sensing lines. However, engineers replaced the ultrasonic FT during the recent refueling outage (OR05) with a Rosemount differential pressure, self-venting transmitter. A significant delay in the output signal of the ultrasonic FT during periods of changing, flow, resulted in poor controller response and higher levels of unidentified RCS leakage during makeup operations. The engineers expected that the self-venting Rosemount FT would provide accurate flow rater, would not be susceptible to gas buildup, and would eliminate the lagging response of the ultrasonic FT. However, this was not the case.
16 The engineers determined during the troubleshooting of this problem, that insufficient distance existed between the orifice flow element (FE 111) and the mixing tee (CS MM-1).
The alt:ance from the mixing tee to FE 111 was 9 inches w'hich is 4.5 pipe diameters in order to obtain an accurate flow measurement from a differential head davice (such as an crifice plate), a predictable velocity profile must be establir.hed within the pipe upstream of the device. The ASMC 3tandard MFC-3M 1989 provided information to determine the required number of upstream pipe diameters from an orifice plate to an upstream component. - The engineers assumed that the mixing tee (which is simply a tee piping connection) behavior-was similar to that of a ball valve t.nd that 25 upstream pipe diameters were required between it and the FE 111.
To resolve the inaccuracy, the engineering staff is developing a design change package to move the FE-111 downstream and install a flew stialghtener to provide the required number of pipe diameters. This modification is planned to be installed in mid September.
The inspector's review of the design package and safety evaluation is on-going, c.
Conclusions The engineering staff performed well to determine the cause of the low indicated flow from the makeup flow totalizer. Several attempts to correct this recurring problem with the makeup flow totilizer have occurred since the plant's initial startup. Engineers efforts to develop a permanent fix for the issue appears to be effective.
E1.2 Design Change a.
Inspection Scoce (37551)
On June 24, the nitrogen supply check valve (NG-V22), to the "C" accumulator failed to open when operators attempted to fill the accumulator with nitrogen. Tho unit was in Mode 4 (hot shutdown with Tave less than 350 F) and the accumulators were not required to be operable by TS. The inspector reviewed the circumstances regarding the valve failure and the work requests, and discussed the issue with the appropriate engineering personnel, b.
Observations and Findinas On June 8, maintenance technicians insponed NG V22, during the refueling outage due to suspected seat leakage. During the inspection, a new disc, spring, and gasket were installed to address the leakage problem. The technician noted that the " blue check" performed for the new disc yielded worse surface contact than the old disc. The system engineer determined that the old disc should not be replaced. Further, the technician noted that the replacement cpring was longer than the original spring. The technician brought this difference to the system engineer's attention, who authorized the technician to install the new spring stating that it would improve the valve's closure ability. The system engineer comp!eted the post-maintenance test on the valve satisfactorily.
After operators could not pressurize the "C" accumulator on June 24, technicians disassembled the valve to determine the cause of the malfunction. A different system
{
17 engineer was present when the technicians breached the valve ano found the disc spring broken. The technicians also checked NG V24 in the "D" accumulator, which had undergone the same work on June 8, and found the same condition. The system engineer concluded that the wrong size spring had been installed during the outage. The original spring was then replaced, and the valve was reassembled, tested satisfactorily, and returned to service.
The spring was part of a rebuild kit supplied from the vendor. The procurement organization failed to recognize that the wrong size spring was provided and stored the spring under the same stock nunter as the correct spring. The system engineer confirmed with the vendor that the spring was a suitable replacement part, but did not perform an engineering work request (EWR) for a component substitution review as per the North Atlantic Design Change Manual, Chapter 2, Engineering Work Requests. An ACR was initiated for this issue and is currently under evaluation. This issue will remain unresolved pending NRC staff review of the ACR evaluation for roct cause and corrective actions.
(URl 50 443/97-04-04) c.
Conclusion The self identifying failure of the check valve precluded the inoperability of the C Accumulator. However, the weak engineering evaluation of a dissimilar component on the system engineers part created the potential for an unauthorized modification of the check valve requiring further licensee and NRC staff review.
E1.3 Heactor Engineer Startup Activities a.
Inspection Scooe The inspector reviewed and assessed several reactor engineering (RE) activities during OROS. The inspector observed RE personnel interface with operations personnel to provide information regarding predicted core characteristics during Cycle 6 and for the low power physics testing (LPPT). The inspector also reviewed some unusual fluctuations in an axial flux map from data taken from one of the assemblies containing failed fuel from Cycle 5.
b.
Observations and Findinas On June 19,' RE personnel provided operations personnel with an overview of expected core characteristics for Cycle 6. The overview presented information regarding the higher anriched Vantage SH fuel assemblies and the impact on peaking factors, axial flux difference, moderator temperature coefficient, control bank reactivity worth, associated technical specifications and setpoints. The inspector considered this interface and discussion between the REs and operators regarding important reactor fuelinformation to be very good.
On June 26, operators made the reactor critical and REs began LPPT. Prior to taking the reactor critical, RE personnel briefed operations personnel on the scope of the LPPT testing, precautions, and industry experience. Operators declared the reactor critical at 3:29 p.m. Critical rod position was 174 steps on Control Bank D. The estimated critical
18 position was at 116 steps on Control Bank D; well within the (+) or (-) 300 pcm limit.
The operations staff appropriately implemented the Special Test Exceptions of TS 3/4.10.3 which suspends several TS limitations during LPPT. RE personnel implemented procedure RS1737, Post Refueling Low Power Physics Testing, and operated the reactivity computer which had been temporarily installed in the control room to collect data while operators performed reactivity manipulations by moving control rods or changing RCS boron concentration. Operators and REs conducted LPPT activities in a professional manner and access to the control room was limited to prevent distractions. The acceptance criteria was met for the tests.
The inspector discussed anomalous neutron flux traces, noted on an axial flux map from one of the fuel assemblies containing failed fuel from Cycle 5, with a core designer from Yankee Nuclear Services Division. Due to the limited number of fixed incore sensors in the assemblies, flux data from these sensors (measured) would be mathematically fitted to produce an axial flux map. The measured flux data would be compared to predicted flux data to generate correction factors that would be used for generating the axial map for nuclear channel factors. The inspector was shown that when the curves of the measured and the predicted flux sloped in opposite directions (i.e., one was increasing and the other was decreasing), the correction factors resulted in a jagged or fluctuating curve for that portion of the nuclear channel factors map. The cause of the differences between the measured and predicted curves was attributable to the measured and predicted axial offset.
Furthermore, the inspector was shown that when the difference between the measured and predicted flux started to significantly diverge (at approximately 10,000 Mwd /MTU 4
burnup), the fluctuation on the nuclear channel factor map began to appear. The RE determined that the fluctuations observed on the nuclear channel factor axial maps were results of mathematical modeling characteristics and not indications of fuel degradation.
c.
Conclusions The RE depa-tment demonstrated good initiative by briefing operations personnel on the expected characteristics of the Cycle 6 core. Also, RE personnel worked closely with operations personnel during the LPPT in a cautious and well coordinated effort. Finally, a core designer demonstrated that mathematical modeling characteristics caused the anomalous fluctuations in the nuclear channel factor maps. Overall, perf9rmance in this area was very good.
E8 Miscellaneous Engineering issues E8.1 (Closed) LER 50 443/97-001 00: Seabrook Station Design Basis Flooding Analysis a.
Insoection Scoce The engineering staff identified, during the 10 CFR 50.54(f) review effort, a condition that was outside the stated station design basis flood analysis as described in the UFSAR, Section 2.4. The condition was identified during a site walkdown. The inspector reviewed the UFSAR section and the issue to determine the safety significance and to assess Seabrook's corrective actions. The inspector independently walked-down the specific site areas of concern.
19 b.
Observations and Findinos The Seabrook Station design basis flood analysis describes two flooding scenarios: 1) a probable maximum hurricane (PMH)/ probable maximum flood (PMF) event; and 2) a local intense probable maximum precipitation (PMP) event. The most limiting design basis flooding event is the PMH/PMF event, which by analysis, produces flood levels on the station to a maximum elovation of 21' mean sea level. An important assumption in the analysis is that the flood water will flow off the site via several flow paths that are specified in the UFSAR. The engineer's site walkdown Identified that concrete curbing and perimeter fence anchoring were not considered in the PMH/PMF anelysis. These obstructions could have impeded the flow of water off site and raised the flood level elevations at several areas to approximately one foot above some door silllevels.
The engineering staff determined the cause of the event to be a misapplication of design inputs and inadequate independent review of the calculations. After completion of a root cause evaluation the licensee issued station work requests to eliminate the obstructions / impediments to water run off during the design basis events. In addition, changes have been made to the design change process to prevent recurrence of the ident:fied concern. Specifically, revisions to the design change manual require interdisciplinary review to evaluate the effect of plant changes on the plant site perimeter in regards to the site flood analysis. This non-repetitive licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-443/97-04-05) c.
Conclusions Station engineers demonstrated a good questioning attitude and knowledge of adverse flooding conditions by identifying the site barriers not considered in the UFSAR. The actual safety consequences of this event were minimal due to the time of discovery and the implementation of prompt corrective actions. The inspector verified design control program changes to be in place and the station personnel were cognizant of the program requirements.
IV. Plant Support R8 Miscellaneous RP&C lssues R8.1 (Closed) LER 50-443/97-005-01 and URI 97-02 01: Misposition of Main Steam Line Radiation Moni.' ors.
This LER was a supplement to the event that was reviewed and closed as a non-cited violation in inspection report 50-443/97-03. The LER met the requirements of 10 CFR 50.73, and the inspectors had no further questions regarding the event.
20 R8.2 (Closed) LER 50-443/96-009 01: Missed Surveillance Primary Closed Cooling Water Rate of Change Monitor Alarm.
This LER was a supplement to the issue that was discussed in Inspection Report 50-443/97 03, and treated as a non-cited violation. No new issues were revealed by the Lt!R.
S8 Miscellaneous Security issues S8.1 (Closed) VIO 97 02 03, Failure To Control Licensee Designated Vehicles as per Security Plan Requirement 1
The inspector reviewed Seabrook's corrective actions in response to the Notice of Violation resulting from the failure to properly control Licensee Designated Vehicles (LDV's)in the a
station protected area. Security initiated a self assessment of the LDV program and those vehicles not requiring LDV status were removed from the LDV list. Fether, if a LDV is out of the station protected area for greater than an established time perivd for an approved activity such as, operational needs, maintenance, repair or security or emergency purposes, the vehicle will be automatically removed from the LOV list. In addition, Security Department Instruction, SDl10002.00, " Control of Vehicles", was revised to instruct the Vehicle Trap Security Officer to determine the reason the LDV is departing the protected area to provide a record of vehicle departures and returns to ensure compliance with the station security progrcm for accountability purposes. The station security manual was also revised to include the requirements for postive control of LDV't.. The inspector verified tr i the corrective actions were compiete and dstormined that they were approprie.te to ediess the identified deficiency. This item is closed.
S8.2 (Closed) VIO 97-03-08, Designated Vehicle Left Unattended With Keys in Ignitlen and Running.
The inspector reviewed the Notice of Violation response to a failure to pioperty control a LDV in the protected area. The resident inspector identified the event during a routine site inspection tour. A LDV was found with the keys in the ignition, engine running and unattended by the operator. Security personnel initiated a station ACR to document the event with a supporting Cause and Failure Analysis. The inspector reviewed the corrective actions for promptness and adequacy and found them to be sat;sfactory. The corrective actions included coaching and counselling the vehicle driver on the requirements for controlling LDV's, in addition, three articles were printed in the station's internal publications to remind all station persennel on the requirements for controlling LDV's. A three foot by-six foot sign was attached to the vehicle gate at ths entrance to the protected area with wording " Vehicle Must BE Attended When Running
- and ' Remove end Control Ignition Keys From Unattended Vehicle." Also, LOV ignition keys have been attached to large a large key ring that has plastic tags e rbossed with the same wordings as the vehic!c antrance gate. The inspector held discussions with security department personnel concerning the violation and verified the completed corrective actinns. The inspector detarmined that the tica nsee'r ;orrective actions were appropriate and timely to prevent recurrence. This item is closed, o
l I
1
21 SS.3 (Closed) LER 50-443/97 S0100: Loss of Duty Firefighter Keys l
On February 12, at 6:15 a.m., tne off-going duty firefighter determined that his shift key ring was missing. This key ring contained a security vital area mar.ter key. A search was conducted of the immediate office area with no success. The firefi hter notified the 0
security department of the problem at 7:50 a.m., and the NRC duty officer was then I
notified as required by 10 CFR 73.71. The security department commenced a security lock changeout which was completed at 5:05 p.m. that day. Subsequently, on May 20, the key ring was found in the primary auxiliary building (PAB) elevation -20 in a cable tray by a station worker. The inspector datermined that this was the first instance of lost security keys at the station.
As a result of this event, Seebrook management instituted the following corrective actions to prevent recurrence. Operations and firefighter personnel were trained in the necessity of prompt notification to the security department concerning loss of security keys, and additional training was given to operations / fire protection personnel on security program requirements for security key control. A station ACR was issued to document the event and the lessons learned and a self-assessment / monitoring program was established to ensuro compliance to the security key control program. At the close of this inspection period all of the corrective actions had been completed with the exception of initial training modules. This is due for completion on September 30 of this year.
The inspector concluded that the security department properly responded to the event upon notification. The inspectors review of vital security door access door logs for the period in question determined that no unauthorized entries or alarms had occurred during the period that the security keys were not under the control of the duty firefighter.
Seabrook provided prompt and adequate corrective actions to correct the identified concern. This non-repetitive licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-443/97-04-06)
P1 Emergency Preparedness (EP)
P2 Status of EP Facilities, Equipment, and Resources a.
hsoe_ction S,qo_p_g Determine whether key facilities and equipment are adequately maintained and determine whether changes made since the last inspection are technically adequate, meet NRC requirements, licensee commitments, and are appropriately incorporated into the ernergency plan and implementing procedures.
Determine whether changes to emergency f acilities, equipment, instrumentation, and supplies have adversely affected the licensee's emergency preparedness program, b.
Observation and Fin.d.inas 1
m s.
e
22 The inspectors toured the control room, technical support center, operational support center, and the emergency operations facility and determined, by random sampling of i
equipment and procedures, that all survey instruments were calibrated as required and emergency plan and that emergency plan implementing procedures were current and up to date, which indicated that the facilities were found to be in a good state of readiness.
(
During the tour of the ficilities and checking of the survey instruments, it was noted that l
batteries were removed from all of the survey instruments to prevent equipment damage caused by battery corrosion and that the wires for the survey instrument speakers were disconnected. It was also noted by the inspector that the point of connection for the speaker wire was not easily identifiable. The inspector checked emergency planning implementing procedure ER 5.2, Site Perimeter and Offsite Monitoring and Environmental Sampling, to determine if there was any guidance in the procedure as where to connect the speaker wire. There was no guidance. Therefore the technician who may be required to use the instrumentation may not know where to connect the speaker wire and would not have the audible capability of the survey instrument. The inspector opened other E-140 instruments and found the same problem.
The licensee immediately took corructive measures to place steps in the procedure and provided a drawing attachment tc the procedure indicating where the connection to the circuit beard was to be made, and that it would also be noted in training.
c.
Conclusion Overall, the facilities were found to be in a good state of readiness. Additionally, changes that were made to the facilitbs were enhancements and did not reduce the licensee's ability to implement the emergency plan.
P3 EP Procedures and Documentation a.
Insoection Scoce if significant or major changes have been made to the emergency preparedness program, assess whether these changes have adversely affected the licensee's overall state of emergency preparedness and have been appropriately incorporated into the licensee's emergency plan and implementing procedures.
Verify that major or significant changes to the emergency plan and implementing procedures have been reviewed, approved, and distributed in accordance with approved licensee procedures and NRC requirements before implementation.
b.
Qbservations and Findinos The inspector reviewed Revision 25 to the Seabrook Station Radiological Emergency Plan and emergency plan implementing procedures which had recently been submitted to the NRC.
23 c.
Conclusion The inspector determined that the changes met the requirements of 10CFR50.54(q) and will continue to be reviewed during further inspections.
P4 Staff Knowledge and Performance in EP a.
Insoection Scooe Evaluate the effectiveness of the licensee's controls in identifying, resolving and preventing problems by reviewing such areas as corrective action systems, root cause analyses, safety committees, and self assessment in the area of emergency preparedness.
Determine whether there are strengths or weaknesses in the licensee's controls for the identification and resolution of the reviewed issues that could enhance or degrade plant operations or safety.
b.
Observations and findinos e
The inspector reviewed the emergency preparedness action item list (EPAll), which is a tracking system that is used by emergency preparedness to track items for the planning for drills and exercises, for planing and implementing facility and equipment up grades, for tracking and taking corrective measures on drill and exercise comments and plan and procedure changes. This tracking system replaces the incomplete items list (llL) tracking system. The site action item tracking and trending system (AITTS) is used to track emergency preparedness adverse condition reports and regulatory items. Additionally, the tracking systems are reviewed monthly as an indicator of upcoming drill and exercise activities and weekly to ensure all drill and exercise requirements are finalized prior to the drill or exercise dates.
The emergency preparedness department maintains a data base on emergency preparedness corrective actions. This data base is used to track audit and inspection report items so that they can trend corrective actions to determine their effectiveness.
Additionally, the licensee has an effective self assessment program. They have completed and taken corrective actions as necessary on six self-assessment since the beginning of 1997. Also they provide information to a key performance indications system which provides trends on emergency preparedness performance.
c.
Conclusion Overall, the licensee has in place effective systems to identify, resolve and take corrective measures in emergency preparedness.
24 P5 Staff Training and Qualification in EP a.
Insoection Scoce interview a small sample of individuals assigned key roles for emergency response to determine whether they have been trained as required and understand their emergency assignments, responsibilities, authorities, and changes to the implementing procedures.
If changes have been made to the licensee's emergency preparedness program since the last inspection, determine whether responsible personnel are aware of the changes, understand them, and have been adequately trained to implement them, b.
Observations and Findinas On July 15, the inspectors observed emergency response organization classroom training, which addressed emergency classification. The inspectors determined that the training instructor was knowledgeable of the course material, all elements of the lesson plans were covered in an effective manner and the course material satisfied the requirements of the Seabrook Station Radiological Emergency Plan (SSREP) and the emergency response organization Training Program Description (TPD). The inspectors further evaluated the effectiveness of the training by conducting table top scenarios with two emergency response managers, two site emergency directors, and two operations crews consisting of three senior reactor operators, in order to determine if the emergency response organization response personnel were being trained in accordance the SSREP, the inspectors randomly selected and reviewed the training records for 60 of 74 emergency response positions, t
c.
Conclusion The inspectors determined, based on the results of the walk through scenario drills and the reviews of the training records, that the emergency response organization was qualified and that training was effective.
P6 EP Organization and Administration a.
Insoection Scoce if changes have been made to the emergency organization or management control systems, determine the effect of these changes on the licensee's emergency preparedness program and verify that these changes have been properly incorporeted into the emergency plan and implementing procedures, b.
Observations and Findinas The emergency preparedness staff has remained the same since the last inspection. The emergency preparedness staff consist of six individuals. The staff consist of well trained, l
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25 professional, and confident individuals. Additionally some of the staff has been involved in assist visits at other utilities and plants in NRC Region I and other NRC Regions.
The emergency response organization has at leest three qualified individuals in all positions.
Since the last inspection the licensee implemented the streamlined emergency response organization. During the 1996 NRC/ FEMA graded exercise the licensee effectively demonstrated the streamlined emergency response organization. The changes to the organization reduced the staffing level of non-essential personnel and moved some of the required functions to other facilities. The fullimplementation of the streamlined emergency response organization was competed on March 28,1997, after all emergency response personnel had received their training and the emergency plan and procedures were approved by the safety operational review committee, c.
ConclusiQD Overall, the emergency preparedness staff and the emergency preparedness organization meet the requirements of the emergency plan.
P7 Quality Assurance in EP Activities a.
Insoection Scope Examine independent and internal review and audit reports for the licensee's emergency preparedness programs since the last inspection to determine compliance with NRC requirements and licensee commitments.
Evaluate the licensee's corrective actions for audit identified deficiencies and those identified during drills and exercises, b.
Observations and Findinog The inspector reviewed Nuclear Safety Assessment Audits 96-A02-02,96-A11-04 and Seabrook Station 1997 Emergency Preparedness Program Assessment.
Audit 96-A02 02 had no findings or observations. Audit 96-A11-04 had no findings and three observations. The observations identified were 1) there were inconsistencies between the emergency preparedness qualification guide and the emergency plan implementing procedures; 2) there was confusion in the implementation of the 60 minute follow up notification to the States, and 3) determination of minimum staffing requirements for the Technical Support Center and Operations Support Center.
The inspector raised concerns that E-Plan audits had been performed by the same Audit Team Leader for several years and that the audits were not of the quality observed in the industry. The Oversight management evaluated this concern under an ACR and concluded that the Audit and Evaluation Group had become complacent with its performance and the quality of audit report had not kept pace with the industry. As corrective actions, l
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26 Oversight management assigned a new Audit Team Leader and revised Audits Plans to better reflect 10CFR 50.54(t) requirements.
The emergency preparedness and training departments immediately provided corrective measures to the observations, c.
Conclusion Overall, the Nuclear Safety Assessments meet the requirements of 10CFR50.54(t).
Oversight management promptly responded to the inspectors concerns and implemented good corrective actions.
V. Manaaement Meetinas X1 Exit Meeting Summary The Emergency Preparedness Specialist presented the inspection results to members of the station's management, following the conclusion of the inspection on July 18.
The inspectors presented the inspection results to members of the station's management, following the conclusion of the inspection period, on September 3,1997. The Station Director acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary No proprietary information was identified.
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- PARTIAL LIST OF PERSONS CONTACTED Seabrook B. Bouchel, Engineering Performance Manager R. Cooney,- Assistant Station Director W. DiProfio, Station Director B. Drawbridge, Director of Services
-G. Kline, Technical Support Manager W. Leland, Chemistry / Health Physics Manager M. Makowicz, Corrective Action Manager R. Messina, Security Supervisor G. Mcdonald, Nuclear Quality Manager J. Peschel, Regulatory Compliance Manager J. Peterson, Maintenance Manager _
T.' Pucko. NRC Coordinator, Regulatory Compliance -
E.-Soretsky, Technical Projects Supervisor G. StPierre, Operations Manager R. White, Mechanical Engineering Manager H&G F. Paul Bonnett, Senior Resident inspector (acting)'
Javier Brand, Resident intern Richard J Conte, Branch Chief 1
William T. Olsen, Resident inspector
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28 INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 40500:
Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems IP 61726:
Surveillance Observation IP 62707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 82205:
Shift Staffing and Augmentation IP 82701:
Operational Status of the Emergency Preparedness Program IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Followup - Engineering IP 92903:
Followup - Maintenance IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Ooened URI 50-443/97-04-01 Diesel Generator Room Deficiency Tags (Section O2.2)
VIO 50-443/97-04-02 Two Safety-Related Procedures Not Revised (Section 03.1)
VIO 50-443/97-04-03 Failure to Perform a Temporary Change to Procedure (Section O3.2)
URI 50-443/97-04-04 Engineering Evaluation of Dissimilar Replacement Components (Section E1.2)
Closed NCV 50-443/97-04-05 Seabrook Station Design Basis Flooding Analysis. (Section E8.1)
NCV 50-443/97-04-06 Loss of Duty Firefighter Keys. (Section S8.3)
URI 50-443/97-02-01 Misposition of Main Steam Line Radiation Monitors (Administratively). (Section R8.5)
VIO 50-443/96-10-02 Emergency Feedwater System Valve closure. (Section 08.6)
VIO 50-443/97-02-03 Failure to Control Licensee Designated Vehicles as per Security Plan Requirements. (Section S8.1)
VIO 50-443/97-03-08 Designated Vehicle Left Unattended With Keys in Ignition and Running. (Section S8.2)
LER 50-443/97-12-00 Reactor Trip and ESF Actuation on Lo-Lo Steam Generator Level. (Section 08.1)
LER 50-443/97-11-00 Containment Building Spray Sump Encapsulations. (Section 08.2)
LER 50-443/97-09-00 Degraded Fuel Rods identified in Westinghouse Fuel Assemblies. (Section 08.3)
LER 50-443/97-08-00 Automatic Reactor Trip and Feedwater Isolation. (Section 08.4)
29 LER 50 443/97 05 01 Misposition of Main Steam Line Radiation Monitors.- (Section.
R8.5)
LER 50 443/97-01-00 Seabrook Station Design Basis Flooding Analysis, (Section E8.1)
LER 50 443/97 S01-00
. Loss of Duty Firefighter Keys. (Section S8.3)
LER 50 443/96-04-01 Emergency Feedwater System Valve Closure. (Section 08.5)
LER 50-443/96 09-01 Missed Surveillance Primary Closed Cooling Water Rate of Change Monitor Alarm. (Section R8.2)
4 30 LIST OF ACRONYMS USED
-ACR:
Adverse Condition Report AITTS Action item Tracking and Trending Jystem ASME American Society of Mechanical Engineers CRS.
Control Room Supervisor DCR Design Change Record DT Deficiency Tag DG Diesel Generator EFW Emergency Feedwater EP Emergency Preparedness EPAll Emergency Preparedness Action item List EOF Emergency Operations Facility ESF Engineered Safety System EWR Engineering Work Request -
FWI -
Feedwater Isolation FME Foreign Material Exclusion gpd Gallons per day gpm Gallons per minute llL Incomplete items List LDV Licensee Designated Vehicle LER Licensee Event Report LCO Limitirig Condition for Operation LPPT Low Power Physics Testing MRT Management Review Team NAPA North Atlantic Procedure Administration NCV Non-Cited Violation NSARC Nuclear Safety and Audit Review Committee NRC Nuclear Regulatory Commission -
OSC Operational Support Center ppm Parts-per million PAB Primary Access Building.
PDT Primary Drain Tank PMF.
Probable Maximum Flood PMH Probable Maximum Hurricane PMP Probable Maximum Precipitation psia Pounds per square inch absolute c
psig Pounds per square inch gauge PZR Pressurizer RCS Reactor Coolant System RCT Root Cause Team RE-Reactor Engineer RHR
' Residual Heat Removal RMW Reactor Makeup Water RWST Refueling Water Storage Tank SG Steam generator SI Safety injection SOO Standing Operating Order
31-SORC Station Operations Review Committee SSREP
' Seabrook Station Radiological Emergency Plan SSPS Solid State Protection System ST
- Surveillance Test TCV
' Temperature Control Valve TDEFW Turbine Driven Emergency Feedwater Pump TPD Training Department Description TS:
Technical Specifications TSC Technical Support Center UFSAR Updated Final Safety Analysis Report VCT Volume Control. Tank WR Work Request l
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