IR 05000327/1998007
| ML20237B190 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 08/04/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20237B172 | List: |
| References | |
| 50-327-98-07, 50-327-98-7, 50-328-98-07, 50-328-98-7, NUDOCS 9808180095 | |
| Download: ML20237B190 (48) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
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Docket Nos: --50-327., 50-328 s " License Nos: OPR-77 DPR-79
' Report No: 50-327/98-07, 50-328/98-07
A Facility: Sequoyah Nuclear Plant, Units 1 & 2 1 ' Location: Sequoyah Access' Road
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Hamilton County. TN 37379
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Dates: June 7 through July 18.-1998
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. Inspectors: M, Shannon,. Senior Resident Inspector R. Starkey,' Resident Inspector l R. Telson, Resident Inspector
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W. Bearden. Reactor Inspector (Sections M1.3, M1.4, and M8.1)
G. Wiseaan Reactor Inspector (Sections F1,1, F1,2,
.F2.1, F2.2, F3.1, F3.2. F7,1, and F8.1)
E. Testa, Senior Radiation Specialist. (Sections R1.1,
.c R1.2, R1.3, R2.1, R8.1, and R8.2)
P. Taylor, Project' Engineer (Section 08.2)
T. Morrissey, Project Engineer Trainee-(Sections M1.3 i
and M1.4)
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' Approved by:
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H. Christensen Chief Reactor. Projects Branch 6 Division of Reactor Projects
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l EXECUTIVE SUMMARY Sequoyah Nuclear Plant. Units 1 & 2 l NRC Inspection Report 50-327/98-07. 50-328/98-07
- This integrated inspection included aspects of licensee operations, l maintenance, engineering, plant support, and effectiveness of licensee i controls in identifying, resolving, and preventing problems; in addition. it includes the results of region based inspections in the areas of fire protection, surveillance, radiation protection and maintenance rule periodic evaluation.
Operations
. Shift turnovers and mid-shift briefings continued to be effective in supporting plant operations (Section 01.1).
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The Management Review Committee (MRC) was effectively performing its duties and plant management was actively involved with the MRC (Section 07.1).
Maintenance
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.A poor work practice was observed related to improper use of protective yellow gloves (Section M1.1).
. The licensee performed a thorough evaluation into the root cause of the Unit 2 turbine driven auxiliary feedwater pump packing failure (Section M1.2).
. The licensee's periodic assessment report provided sufficient detail to demonstrate that the licensee had adequately evaluated performance, condition monitoring, associated goals and preventive maintenance activities for systems, structures, and components within the scope of the Maintenance Rule (Section M1.3).
. The completed preventive maintenance and surveillance test documentation demonstrated acceptable test results (Section M1.4).
. A craftsman failed to meet the licensee's expectation to stop and inquire when uncertain and the licensee failed to ensure a craftsman possessed an adequate understanding of the effects test instruments can have on plant equipment. These failures resulted in a partial loss of power to site security systems (Section M4.1).
I Enaineerina
. A violation with three examples was identified for failure to initiate a PER(s) to identify and promptly correct the deficient conditions exhibited by pressurizer level instrument 2-LT-68-320: for failure to i
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promptly correct the errors in the Unit 2 pressurizer level transmitter calibration procedures and to recalibrates the pressurizer level instruments: and for not following the site's Corrective Action procedure and subsequently not performing an adequate technical operability evaluation (Section E1.1).
. The licensee's record retention program could not provide documentation to support the 1988 change in the pressurizer level instrument calibration procedure or the repair to the pressurizer level sensing nozzles (Section E1.1).
. A violation was identified, with two examples, for failure to meet the calibration requirements of TS 4.3.1.1 for pressurizer level transmitters (Section E1.1).
Plant Sucoort
. Good compliance with plant fire prevention program procedures has resulted in no incidents of safety significant fires within safety related plant areas (Section F1.1).
. The implementation of procedural requirements for using and storing transient combustibles in safety-related areas was good. The material condition in the plant indicated that the various plant departments were properly implementing their responsibilities for combustible material control (Section F2.1).
. The observed level of plant housekeeping reflected good organization and I cleanliness practices on the part of plant workers (Section F2.1).
. The plant fire barrier penetration seal designs were properly supported by seal testing documentation, vendor data, design data, and inspection records. The licensee's fire barrier penetration seal engineering evaluations provided for deviations from fire barrier configurations l qualified by tests satisfied the guidance of NRC GL 86-10 (Section F2.1) i l
. Sufficient procedural guidance was provided to ensure that the capacity l of the RCP oil collection system was being maintained in accordance with l licensee commitments and that the plant operators could identify an oil '
leak from the lubrication system of any one of the RCP motors and take appropriate action. The RCP oil collection system met the licensee commitments identified in the Updated Final Safety Analysis Report for ( compliance to 10 CFR 50. Appendix R Section III.0 (Section F2.2).
. The maintenance and surveillance test program for the emergency 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> battery lighting system was sufficient to assure that the fire protection emergency lighting surveillance requirements established in the UFSAR and 10 CFR 50, Appendix R were met (Section F3.1).
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The scope and content of the post modification testing and surveillance test program for the fire protection water supply system was sufficient to assure that the fire protection system design and surveillance requirements specified in the UFSAR were met. Good procedure adherence, coordination, and communications during the testing was observed (Section F3.2).
- The licensee's 1998 Nuclear Assurance assessment of the facility's fire protection program was comprehensive and effective in identifying fire protection program performance to management. The licensee corrective actions in response to previously identified audit issues were good and had been implemented in a timely manner (Section F7.1). l
. Radiological facility conditions were appropriate and material was labeled appropriately, and areas were properly posted (Section R1.1).
. Personnel dosimetry devises were appropriately worn (Section R1.1).
. Radiation work activities were planned and radiation worker doses were being maintained well below regulatory limits and the licensee was continuing to maintain exposures as low as reasonably achievable (Section R1.1).
- The licensee had effectively implemented a program for shipping and receiving radioactive materials as required by NRC and the Department of Transportation regulations (Section R1.2).
. The licensee's water chemistry control program for monitoring primary and secondary water quality had been implemented, for those parameters reviewed, in accordance with the Technical Specification requirements -
(Section R1.3). ,
. The Total Dose from the 40 CFR 190 calculation for the radiological impact from the facility operation was less than 1% of the regulatory limit (Section R2.1).
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Report Details
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Summary of Plant Status l
Unit 1 and 2 operated at full power for the entire inspection period.
I. Ooerations 01 Conduct of Operations l
01.1 Ge.neral Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
- reviews of ongoing plant operations. In general, the conduct of 1 l -operations was considered to be good. Shift turnovers continued to
. support effective plant operations. Mid-shift briefings effectively
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communicated the status of. ongoing activities. The shift turnovers and mid-shift briefings were considered to be good.
07 Quality Assurance in Operations 07.1 Review Of the Manaaement Review Committee-(MRC)
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- a. Insoection Scope (40500)
L The inspectors observed the performance of the Management Review l l> Committee. (
b. Observations and Findinas i
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The inspectors attended several MRC meetings over the course of the inspection period. The purpose of the MRC is to review problem
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. evaluation reports (PERs) and to approve the disposition of the PERs.
l The committee is chaired by the plant manager and is normally attended L by the site vice president and various department managers. The
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. inspectors noted that the' senior. managers closely reviewed the root causes and corrective actions associated with the individual PERs to 1-ensure that'the deficient conditions were adequately addressed. Senior l l. management oversight has generated a higher quality of root causes and corrective actions that have resulted in improved plant performance, j c. Conclusions l
The inspectors concluded that the MRC is effectively performing its duties and that senior plant management is actively involved in the MRC.
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08 Miscellaneous Operations Issues (92901)
08.1 (Closed) VIO 50-327/98-03-02. Failure of Site Personnel to Initiate a PER After Analysis of the PRT Samole Indicated a Hiah Oxygen
,Concent ration. The inspector verified the corrective actions described in the licensee's response letter, dated May 7. 1998, to be reasonable and complete. No similar problems were identified.
08.2 (Closed) VIO 50-327. 328/97-08-02. Failure to Meet American Society of Mechanical Engineering (ASME)Section XI Code Testina Requirements.
The inspector reviewed the corrective actions described in licensee's response letter of October 21, 1997 and PER-SQ97171141 issued to evaluate this event. The inspector verified that several of the ASME Section XI Code program surveillance procedures were revised to provided more detailed guidance for actions to be taken if valve stroke times are found outside the acceptable range. The licensee also held formal training sessions for personnel responsible for conducting and evaluating the operability of pumps and valves with an emphasis on ASME Section XI Code test program requirements used to demonstrate operability of valves. The inspector determined the licensee's corrective actions were reasonable and complete.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a. Insoection Scone (61726 and 62707)
Using inspection procedures 61726 and 62707, the inspectors conducted frequent reviews of ongoing maintenance and surveillance activities.
The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillance:
- SI-90.82 Unit 2 Reactor Trip Instrumentation Monthly Functional Test
. 2-PI-0PS-062-040.0 Charging Pump Suction Piping Vent
. 2-SI-SXP-003-201.A Motor Driven Auxiliary Feedwater Pump (MDAFWP) 2A-A Performance Test
. 2-SI-SXV-003-219.0 Auxiliary Feedwater (AFW) Check Valve Test During Operation l
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. WO 98-007305 Replacement of the Unit 2 Loop 4 Main Feedwater Regulating Valve (MFRV)
Controller
. 1-SI-SXP-072-201.B Containment Spray Pump 1B-B Performance Test
. 2-SI-SXP 003-201.S Turbine Driven Auxiliary Feedwater Pump 2A-S Performance Test
. 1-SI-CEM-018-116.A Quarterly Chemistry Requirements for Diesel Generator (DG) 1A-A Seven Day Fuel Oil Tank
. 0-SI-0PS-082-007.B Electrical Power System Diesel Generatcr 28-B
. SI-102 M/M Diesel Generator Monthly Mechanical Inspections
. MMI-4.2.3 Monthly Preventive Maintenance of Diesel Generator
. 1-SI-D(P-072-201. B Containment Spray Pump 1B-B Performance Test
. 1-SI-SXP-074-201.B Residual Heat Removal Pump 1B-B Performance Test b. Observations and Findinos The inspectors noted that the preventive maintenance activities and the performance of surveillance activities were adequately performed.
However during performance testing of the 18-B RHR Pump. a licensee employee was observed operating instrument isolation valves and using the plant telephone system while wearing protective gloves. The gloves had been used while temporarily inst 6lling calibrated test gauges on the potentially contaminated RHR system. This observation was not considered significant since no actual system leakage had been observed during the work activity. Additionally, licensee health physics personnel subsequently verified that no radioactive contamination was present in the work area. The inspectors discussed this observation with a member of site 0A management that had also observed the improper use of the protective yellow gloves. No other problems were identified during the observation of preventive maintenance and surveillance testing.
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c. Conclusions In general, preventive maintenance and surveillance activities were adequately performed. 0ne poor work practice was observed associated with the improper use of protective yellow gloves.
M1.2 Review of Root Cause and Corrective Actions for Turbine Driven Auxiliary Feedwater Fumo (TDAFW) Packina Failure a. Insoection Scooe (40500)
Inspection Report 98-06 discussed the inboard pump shaft packing failure on the Unit 2 TDAFW. The inspectors reviewed the licensee's root cause and corrective actions associated with the event as documented in PER No. SO980695PER.
b. Observations and Findinas On June 5, 1998, the licensee initiated PER No. SO980695PER and subsequently the MRC directed that a root cause evaluation be performed.
The root cause evaluation included an analysis performed by TVA Central Laboratories Services of the packing material and pump shaft sleeve.
which had failed: interviews with the packing manufacturer; and interviews with personnel involved with running the pump on June 5. The licensee also reviewed the work history.of the Unit 2 TDAFW pump.
The licensee determined that the root cause of the packing failure was mis-adjustment of the packing which resulted in high friction and heat.
-The heat generated caused the shaft sleeve s carbide coating to separate from the sleeve base metal resulting in failure of the sleeve. The root-cause concluded that the most probable cause was human error associated
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with adjustment of the packing, although the licensee was unable to determine when or by whom the mis-adjustment was performed.
The corrective actions were: (1) Revise tne affected procedure and other maintenance instructions to remove the skill of craft as the method for adjusting the packing and require that the leak off rate be increased to the maximum vendor recommended value of 1/8 inch stream. Verify the l: packing follower is properly engaged in the stuffing box and parallel to
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the stuffing box surface. Evaluate other safety related packing
[ instructions for proper packing adjustment instructions. (2) Include in
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training and brief mechanical maintenance group (MMG) personnel on the L results of the investigation and the sensitivity of the packing adjustments for the AFW pumps. (3) Distribute on the required reading list for operators the details of the investigation and the sensitivity of the AFW pumps and include the requirement that these pumps should never hwe packing adjustments made without the pump in service.
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l l c. Conclusions The inspector concluded that the licensee performed a thorough evaluation into the root cause of the Unit 2 TDAFW pump packing failure.
l M1.3 Maintenance Rule Periodic Evaluation (62706)
a. Inspection Scope Paragraph (a)(3) of the Maintenance Rule required that performance and condition monitoring activities and associated goals and preventive maintenance activities be evaluated taking into account, where practical industry-wide operating experience. This evaluation was required to be performed at least one time during each refueling cycle, not to exceed 24 months between evaluations. The inspector reviewed the licensee's completed periodic assessment to determine if it met the requirements of 10 CFR 50.65, paragraph (a)(3).
i b. Observations and Findinos At the time of the Maintenance Rule inspection, during December 1996 the licensee had not completed their first periodic evaluation. The inspector reviewed the licensee's completed Maintenance Rule Periodic Assessment dated June 26. 1998. This first periodic assessment covered the period from July 10. 1996. until the end of the first calendar quarter of 1998.. The licensee's periodic assessment report consisted of a higher level summary report which summarized information contained in the licensee's Maintenance Rule database and individual system engineer quarterly system health reports rather than a single comprehensive evaluation report. This method was an option allowed by NUMARC 93-01.
" Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Revision 2. The periodic assessment also documented the licensee's balancing between unavailability and reliability for risk-significant systems, structures, and components (SSCs) as required by paragraph (a)(3) of the Rule.
The inspector reviewed the licensee's periodic assessment to verify that the licensee had adequately evaluated goals and monitoring performance criteria, effectiveness of corrective actions, balancing of availability and reliability. and effectiveness of preventive maintenance program.
The inspector also verified that industry operating experience was l
integrated with system engineering, scoping. reviews of functional l failures, and cause determinations. The periodic assessment was conducted in accordance with Section 3.11.3. " Periodic Assessment." of TVA Standard, SPP-6.6. " Maintenance Rule Performance Indicator.
Trending, and Reporting - 10 CFR 50.65." The inspector determined that the licensee's assessment satisfied the requirements of 10 CFR 50.65 and NUMARC 93-01.
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l The next periodic assessment is scheduled for performance during the first caler. jar quarter of 2000 to meet Maintenance Rule requirements for conducting an assessment every refueling cycle, not to exceed 24 months between assessments.
c. Conclusions The licensee's periodic assessment report provided sufficient detail to demonstrate that the licensee had adequately evaluated performance, condition monitoring, associated goals and preventive maintenance activities for SSCs within the scope of the Maintenance Rule. The licensee's assessment met the requirements of NUMARC 93-01 and paragraph (a)(3) of 10 CFR 50.65.
M1.4 Review of Comoleted Surveillance Test Packaaes (61726)
a. Inspection Scooe The inspector reviewed selected completed preventive maintenance and surveillance test packages to verify that the documentation satisfied the referenced Technical Specification (TS) Surveillance Requirements (SRs).
b. Observations and Findinas I
The inspector reviewed test package documentation for the most recent '
performance of the following Surveillance Instructions (sis) and Preventive Maintenance (PM) items:
. 0-SI-MIN-302-239.0. Testing of Divider Barrier Seal .
. 1-SI-MIN-000-001.0, Snubber Visual Inspections ;
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. 2-SI-MIN-061-107.0, Ice Condenser Flow Drains !
. 0-SI-0PS-000-009.0. Actuation of Auto Valves VIA SI Signal for Non-Testable Buric Acid and ECCS Flow Path Valves i
. 0-SI-NUC-000-007.0, Measurement of the At-Power Moderator )
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For those completed SI test packages reviewed, the TS Surveillance i Requirement referenced by the licensee's SI had been satisfied. I Completed surveillance test and PM packages demonstrated acceptable test {
results. No problems were identified with completed surveillance or PM ,
packages reviewed.
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c. Conclusions Completed surveillance test and PM packages demonstrated acceptable test results.
M2- Maintenance and Material Condition of Facilities and Equipment M2.1 480 Vac Westinghouse Tvoe DS 532 Circuit Breaker Deficiencies a. Insoection Scooe (62707)
The inspectors continued to follow the licensee's corrective measures following the failure of a 480 Vac Westinghouse Type DS 532 circuit breaker which led to a May 19. 1998. reactor trip. This issue was previously identified as URI 50-327/98-06-02.
The inspectors continued the review of the potential improper compression setting and potential inadequate post-maintenance testing of the shutdown bus alternate supply breaker. Additionally, the inspectors reviewed maintenance procedures and practices. training of the breaker technicians. the breaker design and vendor refurbishment.
b. Observations and Findinas The inspector reviewed the licensee's extent of condition assessment.
According to the assessment type DS 532 breakers are used in 27 locations at Sequoyah:
. Sixteen Breakers - Two each provide normal and alternate power feed to four 480v shutdown boards per unit. !
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. Eight Breakers - Two each provide normal and alternate power feed to two 480v unit boards per unit, and l l
l e Three Breakers - Three are used in the Turbine Building Common Board to feed from Bus A or Bus B. and for Bustie purposes.
The licensee conducted thermal imaging of the eight DS 532 normal supply
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breakers in the shutdown boards due to concerns over potential main l contact misalignment and/or excessive contact resistance. Observed
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temperatures were normat Thermal imaging was not performed on the unit or common board breakers.
As of. July 18. 1997, six of the 27 DS 532 breakers had been removed for inspection and maintenance. All exhibited various material deficiencies. As-found deficiencies included:
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! . Degradation of closing springs and/or operating mechanisms. This l_ resulted in incomplete travel of the crank arms on several breakers.
L Main contacts were not properly compressed as a result. The licensee L attributed the failure of the 1A-A switchboard alternate supply L breaker to incomplete crank arm travel.
l l. * Excessive bowing of the rear frame piece cf the breakers. This frame l member supports the stationary pole base and affects the ability of f the breaker to be properly adjusted.
. Misadjustment of main contacts. Contacts were found to be out of l
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synchronization and/or in excess of tolerance for proper contact compression.
Thick dust and dry hardened grease were foLnd throughout components of a breaker wnich was removed from the turbine building.
- Excessive trip force requ_ ired to trip some of the breakers.
, The _ licensee continues to investigate the cause of the 480 Vac breaker failure and evaluate as-found conditions for the other breakers.
- c. Conclusions The thermal imaging of the eight shutdown board normal . supply breakers was normal. The inspection of six of 27 breakers has identified various j material deficiencies.
M4 Maintenance Staff Knowledge and Performance M4.1 Loss of Security System Uninterootible Power Sucoly u a. Insoection Scooe (62707)
The inspector conducted an independent review of an event in which an error committed by an electrical maintenance craftsman resulted in a partial loss of power to the site security system. The licensee's assessment, documented in PER No. SO980721PER. PER No. S0980730PER. the-licensee's NRC Event Notification Worksheet and various logs were reviewed.
b. Observations and Findinas i-
-The' inspectors noted that at 11:43 on June 10. 1998, an electrical maintenance craftsman incorrectly measured the output frequency of the
! Security UPS causing the UPS output breaker to trip. The craftsman was not proficient with the test equipment being used (a polymeter) and had l
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incorrectly connected the test leads to the "I" (current) jacks rather than the "V" (voltage) jacks on the face of the meter.
! Discussions with the craftsman indicated that he was unsure at the time
! he configured the instrument as to whether he had set it up correctly but that he did not suspend testing. Instead he proceeded based on the his understanding that, if incorrectly configured the instrument would
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When the craftsman applied the test leads, the UPS output breaker tripped resulting in temporary partial loss of power to site security systems.
L c. Conclusions A craftsman failed to meet the licensee's expectation to stop .and inquire when uncertain and the licensee failed to ensure that a
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instruments can have on plant equipment. _These failures resulted in a l
partial loss of power to site security systems. )
M8' Miscellaneous Maintenance Issues (92902)
M8.1 (Closed) IFI 50-328/97-17 03. Wa+cr Hammer Failure of Heater Drain Flow Control Valve. This itenIhad been opened pending further NRC review of corrective actions associated with the water hammer event which had
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resulted in damage to 2-FCV-6-166A. flow control valve (FCV) for 2C4 to 2C5 feedwater heaters.
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The inspector reviewed PER No. SQ972573PER which documented the I licensee's evaluation of this event. The licensee determined that system piping geometry in conjunction with an abnormal system alignment 3
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nad re.sulted in conditions which had caused the water hammer event. The l licensee further determined that the conditions which had caused the water hammer event could have been avoided if the affected low pressure feedwater strings were isolated anytime the associated Number 4 feedwater heater normal drain paths were isolated. The inspector noted that licensee corrective actions included revision of operating c procedures 1-50-5-1, Feedwater Heaters and Moisture Separator 1
' Reheaters and 2-50-5-1, Feedwater Heaters and Moisture Separator )
Reheaters, to require isolation of the affected low pressure feedwater
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string under the above conditions. Based on this inspection, the E inspector determined that the licensee's corrective actions were
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III. Enaineerina El Conduct of Engineering El.1 Dearaded/InoDerable Pressurizer Level Instruments
.a. Insoection Scooe (37551)
The inspectors continued to review the equipment history. completed surveillance and various problem evaluation reports (PERs) associated with concerns related to calibration and operation of the three Unit 2 pressurizer level (hot calibration) instruments. The review also included the Office of Nuclear Reactor Regulation (NRR) response to a Task Interface Agreement (TIA)98-002, initially submitted to NRR on March 10. 1998, concerning the validity of the licensee *s methodology for conducting calibrations of the pressurizer level transmitters.
b, Observations and Findinas Inspection report 50-327. 328/97-18. initially discussed concerns with the calibration and repair of the three Unit 2 pressurizer level instruments. Following the October 1997 Unit 2 outage the inspectors discovered a control room log entry which documented that pressurizer level instrument 2-LT-68-320 (LT-320) had failed its calibration surveillance. The licensee issued a Technical Operability Evaluation
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"as-left" 18-month TS required calibration (three of nine calibration points were out of specification), did not meet the manufacturer's specifications for hysteresis (required 0.5% vs. as-found 1.0%) and the f instrument had a pressure shift (required 0.2% from 0-1000 psig vs. as L found of 0.84% from 0-94 psig), and was not in conformance with the J scaling documents for generation of the calibration acceptance data. 1 L The'T0E concluded that the pressurizer instrument was acceptable "as-is" '
L and Unit 2 was restarted without repairing the instrument.
e Summary of Pressurizer Level Instrument Issues August 25, 1987: Licensee identified that the pressurizer level i reference leg nozzles were improperly sloped (bent
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March 26, 1988: Work request B-267408 documented that pressurizer reference leg nozzles were bent down and did not meet the required sloping per engineering documents and Westinghouse standards: it documented that 2-LT-68-320 was deviating.4 5% from the other two safety related pressurizer level instruments: and recommended repair of the bent nozzle.
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March 26, 1988: PER No. SQP880272PER was initiated and recommended rescaling pressurizer level 2-LT-68-320 until the bent nozzles could be repaired, March 29, 1988: The calibration procedure for 2-LT-68-320 was l revised / changed by 5.7% and the instrument was ,
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acceptance criteria. No documentation was available to support the procedure revision. Based on discussions with ti:e licensee, the inspectors concluded that the liensee used a (single point)
indicated output from the other two pressurizer level instruments (LT-335 and LT-339) and revised the calibration procedure for LT-320, so that all three instruments would indicate the same, May 24, 1996: 2-LT-68-320 was calibrated, at the TS required 18 l month interval. and three points were just within the acceptance criteria, indicating some degradation from past calibrations which had previously been very close to the " desired values,"
April 30,1997: A PER was initiated to document errors in the pressurizer level scaling documents (both units and all six level instruments). It was a level C PER and it was noted that the errors were only documentation errors. The PER requested that engineering perform containment surveys during the next outage to determine actual component elevations, July 1997: Licensee developed a plan to precisely measure the Unit 2 elevations of the pressurizer level transmitters, sensor bellows, condensate pots, upper taps and lower taps.
October 2, 1997: Unit 2 Refueling outage started.
October 9, 1997: The survey team completed the Unit 2 containment field measurements for each of the pressurizer level instruments.
October 16, 1997: The survey team published a report on the field measurements which confirmed that the drawings and field measurements were consistent and that the errors between the scaling and setpoint documents and calibration procedures could not be explained, w_______ . _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . _ _ _ - _ _ - _ _ _ - _ _ _ _ _ _ . .____ __ _ _- _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - _ _ _ _ - _ _
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October 16. 1997: A work request was initiated to test 2-LT-68-320 for a possible low pressure static shift.
- October 24. 1997: A partial test was performed (0-94 psig) and confirmed a .84% pressure shift. The manufacturer's specification and engineering analysis assumptions for l the instrument was .2% for 0-1000 psig. The original
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to not having a high pressure air flask, engineering used the instrument air header to perform the test and could only get 94 psig. During the test, an engineer heard a popping noise from inside the transmitter as f the transmitter was being pressurized.
OctWer 24, 1997: A calibration was completed on 2-LT-68-320: however, the instrument would not calibrate to within the calibration procedure acceptance criteria.
October 26, 1997: A Technical Operability Evaluation (TOE) was written to address the differences in the scaling / engineering documents and the calibration procedures. It also j discussed the failure to meet the calibration
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procedure acceptance criteria (hysteresis problem).
the pressure sensitivity problem and the popping of the transmitter. The TOE concluded that continued operation was acceptable based on available margin in the instrument accuracy calculations. The TOE did not
! specifically address the pressurizer high level trip setpoint.
Nov. 3, 1997: Unit 2 Mode 2 entry.
Dec. 15, 1997: After several discussions with the licensee and review of the October 26 TOE, the inspectors asked the licensee to provide the supporting documentation for the TOE conclusions.
January 1998: Inspectors asked engineering to provide calibration l procedure revisions for the offset of the calibration.
data. Engineering stated that they did not know when
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the calibration data was changed but probably occurred l in 1990. The inspectors asked maintenance to provide the calibration procedure revision, which identified ,
the 1988 revision. (
l January 9. 1998: Engineering informed the inspectors that the error in the scaling "would cause the high level trip to occur at a value that is conservative with respect to the ,
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Westinghouse setpoint methodology setpoint." This was later identified as being incorrect. The inspectors were also told that the instrument was not degraded per the guidance of GL 91-18.
February 5. 1998: Inspectors were provided an evaluation which supported the TOE. The evaluation noted that the scaling errors-did not adversely affect tne function of the pressurizer high level trip 'Since the error is a negative error, it affects only the decreasing l: setpoints and would not be applicable for the high L
level trip function." The inspectors noted that this conclusion was incorrect and informed the licensee
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that the scaling errors would affect the pressurizer L high level trip, i
Feb. 13. 1998: The licensee revised their evaluation to include the i
proper evaluation for the pressurizer high level trip setpoint.
Feb. 18. 1998: The' inspectors noted that all three pressurizer.
instruments had scaling errors and that actual pressurizer level would be higher than indicated for all.three instruments. Since the instrument bistables were set at 92%. the 1.1% error on 2-LT-68-335 (335)
and the 1.8% error on 2-LT-68-339 (339) would result in not reaching the reactor trip setpoint until 335 reached 93.1% actual level and 339 reached 93.8%
actual level which was above the allowable TS.
tolerance of 92. 7%. After several discussions with the licensee. the pressurizer high level trip setpoints were reduced by 1.9% to 90.1%. Due to 2-LT-L 68-320-indicating approximately 2% lower than 335 and 339, the inspectors concluded that actual level would still have to be greater than 92.7% on 2-LT-68-320
": before it would reach the reactor trip bistable setpoint,
e Failure to Correct and or Initiate a PER For Pressurizer Level Transmitter Deficiencies-l PER No. SO971279PER. initiated on April 30. 1997, documented that i
information provided in the setpoint and scaling documents was not in agreement with the calibration data in the calibration procedures and the supporting accuracy calculations. In July 1997 the licensee ,
developed a-plan to precisely measure the elevation of the pressurizer level transmitters. sensor bellows. condensate pots, upper taps and lower taps. On October 9. 1997. seven days into the Unit 2 outage. the
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! survey team completed the elevation measurements of the Unit 2 i pressurizer level sensing components. On October 16. 1997, the survey team published a report with the documented elevation measurements which l confirmed that the drawings and field measurements were consistent and l that the differences between the scaling and setpoint documents and the l calibration procedures could not be explained.
Pressurizer level instrument 2-LT-68-320 had the most significant difference (approximately 6.0%) and a work request was submitted to troubleshoot the discrepancy. On October 16. 1997, work request (C-325599) was written to test pressurizer level transmitter 2-LT-68-320 for a possible low pressure static shift. On October 24, 1997, a static level shift in 2-LT-68-320 was confirmed. The inspectors were informed that engineering had recommended replacement of the transmitter during the current refueling outage. Engineering also noted that as the transmitter was being pressurized, a popping noise was heard from the transmitter indicating an unexpected shift / movement in the transmitter bellows assembly. The licensee did not initiate a PER to document these deficient instrument conditions as required by the site's corrective action program.
The inspectors also noted that the licensee had not initiated a PER to document the failure of 2-LT-68-320 to meet the acceptance criteria for the required TS calibration performed on October 24, 1997.
On October 26. 1997. a TOE was written to address PER No. SO971279PER.
which identified that the Setpoint and Scaling Documents were not in agreement with the Accuracy Calculations. The TOE documented the instrument pressure shift / sensitivity testing performed on 2-LT-68-320 during the Unit 2 refueling outage. It stated that the transmitter had been subjected to a pressure of 0-94 psi; that the instrument exhibited a static pressure shift of 0.825% from 0-94 psig; that the maximum static pressure shift specified by the manufacturer was 0.2% from 0-1000 psig: that the instrument also exhibited a hysteresis shift of 1.0%
during its calibration; and that the maximum hysteresis specified by the manufacturer was 0.5%. The TOE concluded that although the instrument did not meet the manufacturer's specification, enough margin existed in the instrument accuracy calculation to justify its continued operability.
During the review, the inspectors noted various deficiencies in the licensee's corrective actions which were in violation of 10 CFR 50.
l Appendix B. Criterion XVI requirements. The following examples were l. identified where the licensee failed to correct the deficient
! pressurizer level instrument conditions prior to Unit 2 startup on l November 3. 1997:
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. The licensee identified a static pressure shift problem with 2-LT-68-320, in that the transmitter was experiencing a 0.825% shift
- from 0-94 psi which exceeded the manufacturer's specification of l 0.2% from 0-1000 psig, l
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l . the licensee identified an instrument hysteresis problem with 2-LT-68-320 in that the instrument was experiencing a hysteresis shift of 1.0% which exceeded the manufacturer's specification of 0.5%. This 0.5% design. specification was assumed and documented l in several other engineering documents.
l . pressurizer level channel 2-LT 68-320 failed to meet the "as-left"
acceptance criteria specified in the 18-month channel calibration surveillance procedure 2-SI-ICC-068-320.3. and
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pressurizer level instrument 2-LT-68-320 exhibited a popping noise when pressurized indicating a deficient condition with the instrument.
Based on guidance from Generic Letter 91-18. Revision 1, the inspectors concluded that the above items were degraded and non-conforming
. conditions and would require the licensee to resolve the degraded and non-conforming conditions at the first available opportunity. Since the licensee failed to resolve the degraded and non-conforming conditions during the Unit 21997 fall refueling outage and initiate a PER, the-inspectors concluded that the licensee was in violation of 10 CFR 50.
. Appendix B, Criterion XVI requirements for not taking prompt corrective l actions to correct conditions adverse to quality. In addition TIA 98-
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002 documented that "the staff finds that the operability of the instrument.2-LT-68-320 was not justified by the licensee per the l
guidance of GL 91-18." The failure to identify in the corrective action system and to take prompt corrective actions to correct the deficient-conditions with 2-LT-68-320 is considered a violation (VIO 50-328/98-07-01).
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e. Failure to Promptly Correct Scaling and Calibration Deficiencies Related
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to All Three Unit 2 Pressurizer Level Instruments In April 1997 the licensee identified the discrepancy between the setpoint and scaling' documents and the three Unit 2 pressurizer level instrument calibration procedures. The discrepancies were confirmed during the Unit 2 containment survey in October 1997.
The inspectors reviewed the setpoint and scaling documents. The scaling documents noted that all three Unit 2 pressurizer level transmitters had errors between.the scaling documents and the calibration procedures. 2-LT-68-320 had'a scaling error of 6.2% (16.15 inches-cold calibration)/(32.6 inches normal hot operation). 2-LT-68-335 had a L
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scaling error of 1.1% (2.82 inches-cold calibration)/(5.7 inches-normal hot operation), and 2-LT-68-339 had a scaling error of 1.8% (4 73 inches-cold. calibration)/(9.6 inches-normal hot operation). All of the errors were such that the indicated level would be less than the actual level by the percentages and inches noted above.
Based on.the review, the inspectors concluded that the. licensee had failed to. correct the pressurizer level instrument calibration procedures during the Unit 2 refueling outage and failed to properly i
calibrate all three instruments prior to plant startup. This resulted l: in non-conservative pressurizer high level reactor trip setpoints for all three Unit 2 pressurizer level channels. The failure to take prompt corrective actions to correct the pressurizer level instrument calibration procedures and to recalibrates the level instruments is considered to be the second example of violation (VIO 50-328/98-07-01).
On February 18, 1998, the licensee lowered the pressurizer high level
- trip setpoints.to approximately 90.1% to account for the 1.1%-1.8%
l -component elevation measurement errors. The inspectors reviewed the
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procedure changes and the bistable ca'forations related to the reduction in the reactor protection system channel trip setpoints. The changes
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appeared to be acceptable, e Deficient Technical Operability Evaluation (T0E)
Based on a review of the October 26, 1997. T0E and the supporting l
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Pressurizer Level Transmitter Loop Evaluation for 2-LT-68-320, the inspectors concluded that the licensee had not adequately evaluated the l impact of the incorrect scaling and the related effects on the pressurizer high level reactor trip function. The TOE addressed engineering design calculations and Emergency Operating Procedure (EOP)
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setpoints but did not specifically address the non-conservative effect of_ the improper scaling on the pressurizer high level trip setpoint.
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The inspectors concluded that this omission was due to an error in the
! licensee's evaluation which stated. "Since the error is a negative
' error, it affects only the decreasing setpoints and would not be applicable for the high level trip function."
Site Standard Practice SSP 3.4, Revision 22, Corrective Action. Appendix
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M. Engineering Evaluations for Operability Determination, Section 3.4 Technical Evaluation of TOES, Subsections B.2 and B.4 requires the evaluator to " evaluate the specified function of the affected system, subsystem, or component...by describing the effects of the potential nonconformance/ degraded condition in relation to the components / system's capability of performing its specified function." Subsection B.4.b, requires the evaluator to " evaluate and discuss the effects of the potential nonconformance at the lowest applicable level and continue the
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discussion up through higher levels until a conclusion can be reached l~
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, 17 concerning the effects of the potential nonconformance on system functionality."
In addition, the October 26. 1997 Section 2.2 of the TOE stated.
~ Proper loop scaling is necessary to provide the required accuracy of level i.dication to the main control room operator. Additionally, any limits with the reactor trip function must also be evaluated for impact based on the potentially incorrect loop scaling." The inspectors observed that the licensee limited the TOE discussiori and focussed on an evaluation for the scaling effects on the E0P setpoints.
The inspectors concluded that the licensee had failed to adequately evaluate and discuss the effects of the potential nonconformances of pressurizer level instrument 2-LT-68-320 on the reactor protection system pressurizer high level reactor trip setpoint. The inspectors concluded that the licensee failed to adequately evaluate the affects of the improper scaling on the pressurizer high level trip function was identified as the third example of violation (VIO 50-328/98-07-01).
e Invalid Calibration of Pressurizer Level Transmitter 2-LT 68 320 On October 24. 1997 using surveillance procedure 2-SI-ICC-068-320.3, the licensee attempted to calibrate pressurizer level transmitter 2-LT-68-320. However, the transmitter could not be calibrated to within its required as-left tolerance of 0.5%. A deficiency notice (DN) was initiated for the inability to meet the acceptance criteria in the calibration procedure. On October 26, 1997, a technical operability evaluation (TOE) was completed which concluded that although the pressurizer level instrument did not meet the acceptance criteria of the calibration procedure, operation of the pressurizer level instrument LT-320 was acceptable. The TOE was used to resolve the DN issue.
During the subsequent reviews, the inspectors verified that the 0.5%
tolerance was specified in (1) the pressurizer level instrument 18-month TS calibration procedure: (2) the manufacturer's technical manual (SON-VTD-W120-0630. Westinghouse Model 764 Differential Pressure Electronic Transmitter. Manufactured by ITT Barton): (3) engineering procedure SON-EEB-PL&S (Precautions. Limitations, and Setpoints for NSSS): (4)
engineering document SSD 2-L-68-320 (Setpoint and Scaling Document for Instrument Loop No. 2-LT-68-320); and (5) was an assumed value in engineering design calculation SON-EEB-MS-TI28-0050 (Demonstrated
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Accuracy Calculation). Based on the above design documents, the t
inspectors concluded that the 0.5% accuracy specified in the calibration procedure would be the "necessary range and accuracy ~ specified by the TS definition of channel calibration.
TS 4.3.1.1 requires that. "Each reactor trip system instrumentation channel and interlock shall be demonstrated OPERABLE by the performance
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l 18 of the CHANNEL CHECK. CHANNEL CALIBRATION and CHANNEL FUNCTIONAL TEST operations for the MODES and at the frequencies shown in Table 4.3-1."
Table 4.3-1. Reactor Trip System Instrumentation Surveillance Requirements. Functional Unit 11. Pressurizer Water Level High, requires a channel calibration during each refueling (at least once per 18 months). CHANNEL CALIBRATION is defined by TS 1.4 as "the adjustment, as necessary, of the channel output such that it responds with the
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necessary range and accuracy to known values of the parameter which the t
channel monitors."
In addition, the UFSAR. Section 7.2.3.1. Inservice Tests and Inspections, Item 2. Channel Calibration, states "A channel calibration consists of adjustment of channel output such that it responds. within
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acceptable range and accuracy, to known values of the parameter which the channel measures...Thus, the calibration ensures the acquisition and presentation of accurate information."
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Based on the inspector's review and the TIA 98-002 response from NRR it was determined that a CHANNEL CALIBRATION, as defined by TS 1.4. was not performed as required on October 24, 1997, when the channel output of pressurizer level channel 2-LT-68-320 was not adjusted to the necessary range and accuracy to known values of the parameter which the channel monitors. During the performance of the calibration, per 2-SI-ICC-068-320.3. Channel Calibration of Pressurizer Level II Rack 9 Loop L-68-320.
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2-LT-68-320 failed to meet the as-left acceptance criteria of the calibration procedure. The invalid calibration and failure to meet the calibration requirements of TS 4.3.1.1. is identified as the first l example of violation (VIO 50-328/98-07-02).
Additionally, the inspectors determined from a review of completed surveillance that the pressurizer level instrument calibration procedure calibration data was revised in 1988. Work request B-267408.
dated March 26. 1988, documented that pressurizer level channel 2-LT-68-320 was deviating approximately 4.5% from the other two pressurizer
! level channels. PER No. SOP 880272PER was initiated to address this l
problem. The PER stated that. "The pressurizer tap for 2-LT-68-320 did
! not meet the Westinghouse I&C Standards or TVA drawing 47W600-172 l requirements for slope towards the pressurizer. The condensate pot is
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bent down (approximately 4%). and the head value for the transmitter l scaling is incorrect as a result of this condition." The PER recommended corrective actions to "rescale the transmitter to compensate for error in head and accept-as-is until the implementation of DCR 2191 to rework piping and valves for condensate pot."
The licensee revised the calibration procedure to account for the bent piping from the pressurizer to the condensing pot. The licensee rescaled the pressurizer level transmitter calibration for 2-LT-68-320 by approximately 14.9 inches (cold calibration) or approximately 5.7%.
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l The licensee could not explain why the calibration procedure was revised 5.7% when a deviation of only 4.5% had been identified. The licensee could not provide a documented basis for the calibration procedural change or engineering calculations based on the scaling documents to support the procedure revision. In addition. the inspectors concluded that based on the piping configuration from the pressurizer to the
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condensing pot, the bent piping should not have resulted in the 4.5%
deviation from the other two pressurizer level instruments.
PER SQP880272PER documented detailed procedural requirements for rebending the pressurizer level sensing nozzles back into conformance with specifications which included non-destructive testing of the piping and welds following completion of the pressurizer nozzle bending evolution. During the Unit 21997 fall refueling outage, engineering verified that all three level instrument sensing lines were sloped upwards to the condensing pots as required. However, the licensee was unable to provide documentation to support any repairs or subsequent NDE testing of the pressurizer nozzles concerning the 1987 and 1988 documented line deficiencies.
The inspectors concluded that 2-LT-68-320 has not received a valid calibration since 1988 when the instrument calibration procedure was revised, based on indicated differences from the other two safety related pressurizer level instruments. In 1988. the input pressure calibration data contained in calibration procedure. 2-SI-ICC-068-320.3.
Channel Calibration of Pressurizer Level II Rack 9 Loop L-68-320. 2-LT-68-320 was revised approximately 5.7%. Operators had observed a 4.5%
difference in level between LT-320 and LT-335/LT-339.
Subsequently, in October 1997, the licensee also identified that LT-320 had a pressure shift but failed to verify the extent of the shift. A test was performed on LT-320: however, the partial pressure shift test 3 was only performed from 0-94 psi and a 0.84% pressure shift was I identified. This did not account for or resolve the 5.7% difference between the scaling documents and calibration procedure. The inspectors concluded that the licensee had not quantified or verified the amount of the pressure shift over the design or operating pressure ranges of the pressurizer level transmitter. In addition, the inspector's review of pressurizer level data from the November 1997 Unit 2 startup, indicated that LT-320 exhibited a non-linear level shift as actual pressurizer level varied.
On October 26, 1997. the licensee evaluated the pressure shift condition i and concluded that the calibration was acceptable. However, the inspectors concluded that the licensee had evaluated the adverse
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condition of the pressure shift / sensitivity of LT-320 based on l unverified assumptions. This conclusion was based on the failure of the
- licensee to verify the pressure shift over the full pressure range of
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the instrument and the failure of the licensee to verify the linearity of the instrument at operating pressure. In support of this conclusion.
TIA 98-002 documented that "the staff finds that the licensee's calibration without consideration of the setpoint methodology uncertainties and accuracies does not meet the TS definition of calibration." Therefore, the inspectors concluded that the calibration of pressurizer LT-320 was not valid in that the licensee could not ensure that the instrument would " respond with the necessary range and accuracy to known values." This is considered to be another example of an invalid calibration and failure to meet the calibration requirements of TS 4.3.1.1, and is identified as the second example of violation (VIO 50-328/98-07-02).
- Licensee Positions Concerns with the operability and reliability of the pressurizer level instruments were discussed with the licensee on several occasions during January and February 1998. The licensee concluded that the level instruments were operable and were not degraded. Based on the licensee's calculations completed on February 13. 1998. the licensee's position concluded that " pressurizer level transmitter 2-LT-68-320 meets all engineering requirements such that there is no loss of quality or functional capability. Therefore this instrument is not " Degraded" or
"Non-Conforming" as defined by GL 91-18 Rev.1. Quality is defined as conformance to engineering requirements necessary for the channel to perform its intended function." The licensee also stated that for the failure of pressurizer level instrument 2-LT-68-320 to meet its acceptable as-left calibration surveillance that "This evaluation (October 26. 1997 TOE) determined that the calibration was acceptable to meet all engineering requirements prior to closure of the Surveillance Instruction." The inspectors did not agree with these licensee positions as discussed in the previous sections of this report.
The licensee concluded that the safety significance of these issues
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identified in this report was low due to the~ pressurizer high level trip
.being a backup trip to the reactor coolant system high pressure trip.
Based on the backup function of the trip, the inspectors noted that the deficiencies with the pressurizer level instruments were not a significant safety concern.
i l The licensee concluded that shifting the zero' adjustment to obtain i similar level indications, based on indications from the other level transmitters was an acceptable practice for calibrating safety related instruments. "The calibration of 2-LT-68-320 has been performed utilizing values that are either known by field measurements or known by field comparison and verified by diverse instrumentation. Therefore. !
the calibration of 2-LT-68-320 satisfies the definition of Channel l Calibration as defined by TS and is operable." The inspectors, with '
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concurrence from NRR (TIA 98-002) did not agree that shifting the zero adjustment to obtain similar level indications, based on indications from other similar transmitters, was an acceptable practice for calibrating safety related instruments.
c. ' Conclusions A violation with three examples was identified for failure to initiate a PER(s) to identify and promptly correct the deficient conditions
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exhibited by pressurizer level instrument 2-LT-68-320 for failure to promptly correct the errors in the Unit 2 pressurizer level transmitter calibration procedures and to recalibrates the pressurizer level instruments: and for not performing an adequate technical operability evaluation.
The licensee's record retention program could not provide documentation to support the 1988 change in the pressurizer level instrument
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calibration procedure or the repair to the pressurizer level sensing nozzles.
A violation was identified, with two examples, for failure to meet the calibration requirements of TS 4.3.1.1.
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E8 Miscellaneous Engineering Issues (92903)
E8.1 '(Closed) Unresolved Item 50-328/97-18-04. Resolve Issues Related to l Pressurizer Level Instrumentation. The inspectors completed the review of the various issues regarding calibration and corrective action related to the Unit 2 pressurizer level transmitters. The inspectors's resolution of the pressurizer level instrument issues was supported by TIA 98-002, which was completed by NRR during this inspection period, This unresolved item is being closed based on the identification of three violations which are documented in Section E1.1 of inspection report 98-07.
IV. Plant Suooort F1 Control of Fire Protection Activities F1.1 Fire Reoorts and' Investigations a. Insoection Scoce (64704)
The inspectors reviewed the plant fire-incident reports and fire brigade dispatch records for 1998, to assess maintenance related or material condition problems with plant ' systems and equipment that initiated fire events. The inspectors verified that plant fire protection requirements u __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ . - - - - - _ _ _ _ _ - _ _ - - _ _ _ _ _ _ - - _ _ _ _ _
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were met in accordance with SSP-12.15. " Fire Protection Plan." Revision 20, when fire related events occurred.
b. Observations and Findinos The fire incident reports and selected fire brigade dispatch logs l
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-indicated that there was one minor incident of fire within a safety related plant area thus far, in 1998. which required -fire brigade re-sponse and the licensee's fire protection staff investigation. This incident involved a small welding slag fire on February 24, 1998.
1.icensee personnel identified and extinguished the fire condition prior to the arrival of the fire brigade. No safety significant fires had occurred during this period. This indicated good compliance with the fire prevention program procedures.
c .- Conclusions Good compliance with plant fire prevention program procedures resulted
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in no incidents of safety significant fires within safety related plant
. areas. thus far, in 1998.
F1.2 Combustible Material Controls / Fire Hazards Reduction a. Insoection Scooe (64704)
The-inspectors reviewed procedures FPI-0100. Revision 0. " Control of Transient Combustibles." and SSP-12.71. Revision 2, " Housekeeping." for compliance with.the NRC requirements and guidelines and also toured selected safety and non-safety related plant areas to inspect the !
licensee's implementation of these procedures.
b. Observations and Findinas Procedure SSP-12.71 delineates the duties and responsibilities for implementing'the_ plant general housekeeping requirements.
Procedure FPI-0100 establishes the requirements and controls to be provided.for handling and use of transient combustibles associated with maintenance, modifications. and operations activities.
The inspectors toured the emergency diesel generator building, emergency raw cooling water (ERCW) building. turbine building, new fire pump
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l- house, and the Unit 1 and 2 auxiliary and control buildings with the licensee's fire protection engineer. The inspectors observed that'
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controls were being maintained for combustible liquid leaks in areas o containing lubrication oil and diesel fuel, such as the diesel generator rooms. Although there were several small leaks from equipment, the
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leakage was being contained by the use of oil absorption materials that were replaced at frequent intervals.
Lubricants and oils for normal maintenance activities were placed in I approved safety containers and properly stored inside approved fire resistive flammable liquids storage cabinets. The doors of these storage cabinets were properly closed and latched.
The inspectors also verified that the majority of the wood used during work activities was treated to make it fire retardant. The inspectors observed that the work areas were cleaned of unnecessary material.
Waste material trash cans utilized safety covered lids and were emptied on a frequent, regular basis.
The inspectors concluded that the various plant departments were properly implementing their responsibilities for combustible material control. The observed level of plant housekeeping reflected good organization and cleanliness practices on the part of plant workers.
c. Conclusions The implementation of procedural requirements for using and storing transient combustibles in safety-related areas was good. The material condition in the plant indicated that the various plant departments were properly implementing their responsibilities for combustible material control. The observed level of plant housekeeping reflected good organization and cleanliness practices on the part of plant workers.
F2 Status of Fire Protection Facilities and Equipment F2.1 Fire Barrier Penetration Seals a. Insoection Scooe (64704)
The inspectors reviewed the fire barrier penetration seal designs and testing. The inspectors compared selected as-built fire barrier penetration seals to fire endurance test configurations to verify that those seals were qualified by appropriate fire endurance tests and representative of the design and construction of the fire endurance test specimens. During plant walkdowns the inspectors observed the installation configurations of selected fire barrier penetration seals to confirm that the licensee had established an acceptable design basis for those fire barriers used to separate safe shutdown functions.
b. Observations and Findinas Fire barrier penetration seals are used to prevent the spread of fire between fire areas to ensure separation of redundant safe shutdown
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l equipment. Laboratory testing.of fire barrier penetration seals is done
.only on a limited range of test assemblies. In-plant installations can I
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vary from the tested configurations. Under-the provisions of Generic I Letter (GL) .86-10. " Implementation of Fire Protection Requirements."
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licensees are permitted to develop engineering evaluations justifying !
such deviations. j I The inspectors reviewed the silicone foam design criteria documentation.
l Sequoyah Nuclear Plant computer database fire barrier seal design j i records, penetration seal typical detail drawings, seal inspection i summary records, testing records, and engineering evaluations. At i Sequoyah there were 77 typical penetration seal types and 27 fire tests I which supported their configurations. The review included eleven l- mechanical and electrical fire barrier penetration seal types.
The inspectors reviewed Sequoyah design criteria document No. SON-DC-V-36.0 " Design Criteria for Mechanical Penetration Seal Assemblies for Category I Structures." Revision 1., and System Description Report.
l- " Penetration Seal Engineering Report No. N2-302-400." Revision 0 to assess the licensee's supporting technical justifications and available engineering evaluations for the sampled silicone foam type penetration seals.
The system description report documented the design inspection program.
and qualification of the fire rated penetration seals at Sequoyah. The report provided information on the design basis, design details and fire test data to substantiate the penetration seal designs. The report also identified the testing standards used ano provided engineering justifications (calculations) for the design details which did not fully meet the referenced testing standards.
Using the fire protection penetration seal engineering report and-penetration seal computer database forms to determine the location and description of the plant fire barrier seals, the inspectors conducted walkdowns and inspected penetration seal installations. The inspectors'
review focused on verifying-that the following design and installation parameters for the as-built configurations were adequately bounded and justified by the licensee's engineering evaluations:
e penetration type and opening sizes, e seal material type and depth, e damming material type and orientation.
e thermal mass of penetrating items. and e clearances of penetrating items.
i No discrepancies were identified by the inspectors in the review of the licensee's fire barrier penetration seal design criteria. computer database forms, installation procedures, seal inspection rctords.
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engineering evaluations and the visual inspection of the seal installations. The inspectors determined that the documented licensee's inspections of the silicone foam seal material installed under damming boards were effective in verifying that no inte tal gaps or voids existed.due to poor seal installation methods. The inspectors concluded that the fire barrier penetration seal designs were properly supported by seal testing documentation, vendor data, design data, and inspection records. .The licensee's fire barrier penetration seal engineering evaluations'provided for deviations from fire barrier configurations qualified by tests satisfied the guidance of NRC GL 86-10. Also, the inspectors did not identify any degradation of seal integrity or missing seals.
c. Conclusions
'The inspectors- concluded that fire barrier penetration seal designs were properly supported by seal testing documentation, vendor data, design data, and inspection records. The licensee's fire barrier penetration-seal engineering evaluations provided for deviations from fire barrier configurations qualified by tests satisfied the guidance of NRC GL 86-10.
F2.2 Reactor Coolant Pumo (RCP) Oil Collection System a. Insoection Scooe (64704)
The inspectors reviewed-the design, operation, and maintenance of the oil collection system for the reactor coolant pumps to verify that the requirements of UFSAR Section 9.5.1, the Sequoyah " Fire Protection Report." (FPR) and 10 CFR 50, Appendix R.Section III.0 were met, b. Observations and Findinas The inspectors reviewed UFSAR Section 9.5.1. " Fire Protection System."
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the Sequoyah FPR. Part V. " Emergency Lighting and Reactor Coolant Pump 011 Collection," Revision 0, operator annunciator response procedure 1-
'AR-MS-B. "CVCS Seal-Water and RCP.1-XA-55-5B." Revision 20, surveillance instruction SI-137.1. " Reactor Coolant' System Unidentified Leakage Measurement." Revision 19. and other related documentation.
l The inspectors reviewed the procedures and interviewed the system l -engineer:and determined that sufficient _ procedural guidance was provided l: to _ verify that _the RCP oil collection system reactor building pocket sump inventory was' monitored and routinely discharged of fluid to
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. maintain' an adequate capacity to hold the oil resulting' from the largest
. oil spill on a RCP. This met the licensee's commitments for compliance to 10 CFR 50, Appendix R Section 111.0.
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The inspectors also verified that during plant operation, loss of oil from the RCP motor lubrication system would be detected by the RCP motor oil reservoir "hi/lo". level alarm. If the oil level in the oil l reservoir of- any RCP motor reached above or below the normal level, an i alarm would be received in the control room prompting the operators to
[ pump down the reactor building pocket sump and increase monitoring of l the available RCP bearing temperatures.
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The inspectors concluded that sufficient surveillance testing and operations procedures were in place to ensure that the capacity of the RCP oil collection system was being maintained in accordance with commitments made to the NRC for compliance to 10 CFR 50. Appendix R.
Section 111.0.
c. Conclusions Sufficient procedural guidance was provided to ensure that the capacity of the RCP oil collection system was being maintained in accordance with licensee commitments and that the plant operators could identify an oil l leak from the lubricatiori system of any one'of the RCP motors and take appropriate action. The RCP oil collection system met the licensee commitments identifled in the UFSAR for compliance to 10 CFR 50 Appendix R.Section III.O.
F3 Fire Protection Procedures and Documentation F3.1 Surveillance Procedures for ADDendix R Emeraency Liahtina a. Insoection SCoDe (64704)
The inspectors reviewed the design, operation. and the surveillance testing program for the self-contained 8-hour battery powered emergency lighting system to verify that the requirements of UFSAR Section 9.5.3.
~ Lighting Systems." SSP-12.15. " Fire Protection Plan." Revision 20. and 10'CFR-50 Appendix R.Section III.J were met.
<
b. Observations and Findinas The inspectors reviewed UFSAR Section 9.5.3, the fire protection plan, periodic instruction 0-PI-FPU-247-001.0 " Emergency Lighting (Appendix R)." Revision 3 and abnormal operating procedure A0P-C.04. " Control Room Inaccessibility." Revision 0, and other related documentation.
The' inspectors toured selected plant areas associated with the operation of post-fire alternate shutdown equipment described in A0P-C.04 and noted that the installed. emergency battery lighting was well maintained and.the material condition was very good. The inspectors' review of the maintenance and testing procedure and discussions with the facility fire protection engineer indicated that the scope and content of the periodic l
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i L 27 i test procedure was sufficient to perform good verification of the emergency battery lighting units' performance. The procedure was well written and verified that the emergency battery lighting units were
, operable, correctly aimed to illuminate post-fire alternate shutdown l. equipment and.the working condition of the lighting unit's batteries were of adequate capacity. This provided good verification that the emergency 8-hour battery lighting system met the fire protection
' surveillance requirements of the Fire Protection Plan. UFSAP,Section 9.5.3 and 10 CFR 50. Appendix R.Section III.J.
L c. Conclusions l
The maintenance and surveillance test program for the emergency 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> battery lighting system was sufficient to assure that the fire protection emergency lighting surveillance requirements established in j- the UFSAR and 10 CFR 50. Appendix R were met.
t F3.2 Post Modification and Surveillance Testina of the Fire Protection Water
- Pumo Suoolv and Pioinq _
. a. Insoection Scooe (64704)
The inspectors reviewed the operation. post modification testing and l the surveillance test program for the new-fire protection water pump supply and piping system for compliance with the licensee's commitments to the NRC established in UFSAR Section 9.5.1.
b. Observations and Findinas L The modifications included the installation of two fire protection water supply tanks two fire pumps. a fire pump house, and the replacement of
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piping and valves inside the power block. The inspectors * review of the ;
functional- testing for'the modifications were documented in integrated
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inspection report 50-327. 328/97-14.
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.The inspectors reviewed completed fire protection water system post
- modification testing procedures 0-SI-FPU-026-196.R. " Diesel Fire Pump Battery 18-Month Inspection." Revision 0, 0-SI-FPU-026-201.R, " Motor
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Driven Fire Pump A - 18-Month Flow Test." Revision 0. 0-SI-FPU-026- i 200.R. " Diesel Driven Fire Pump B - 18-Month Flow Test." Revision 0, 1 SSP-8.1. " Motor Driven Fire Pump B - Logic and Field Acceptance Test." l Revision 7. and other related documentation. The inspectors also performed walkdown inspections of the two water supply tanks. the fire i pump house and the new fire pumps to verify the system alignment. No {
discrepancies were noted. The inspectors concluded that the completed -
post modification testing conducted for the high pressure fire protection water system was effective. Testing deficiencies were j
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properly documented and corrected in accordance with plant fire protection plan procedures.
The inspectors also observed ongoing fire protection water supply
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surveillance activities. The inspectors observed portions of surveillance test. 0-SI-FPU-026-002.Y. " Auxiliary Building.and Diesel Generator Building System 26 Flow Test." Revision 2. which verified the
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flow capabilities of the fire protection water supply and interior loop
! piping. The test was performed in accordance with approved test i procedures and good test practices. Good procedure adherence.
. coordination. and communications during the testing were observed. Test l results indicated that the fire protection water flow and water pressure ( requirements established in the UFSAR were met.
l c. Conclusions The scope and content of the-post modification testing and. surveillance
,- test program for the fire protection water supply system were sufficient
! to assure that the fire protection system design and surveillance l
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requirements specified in the UFSAR were met. Good procedure adherence.
coordination, and communications during the testing were observed.
F7. - Quality Assurance in Fire Protection Activities l
F7.1 Fire Protection Audit Reports (64704)
a .- Insoection Scooe The inspectors reviewed the Nuclear Assurance (NA) Audit Report SSA-98-02. " Fire Protection and-Loss Prevention Program (Triennial)." dated
'~ July 1._1998. and the status of the corrective actions implemented for the PERs initiated for the audit report.
b. Observations and Findinas ine licensee's Nuclear Assurance performed an assessment of the fire protection program during the time period from March 31 to June 4.1998.
The report for this assessment was Report No. SSA.-9802. This audit
- included -ight assessment of the fire protection program as
! applied to Ti tection systems, fire barrier and penetration seal program, fire iod, og, fire protection equipment, maintenance and i surveillance procedures, training and qualification, transient combustible controls, self-assessments, observations. regulatory issues, and plant modifications. The assessment report identified no audit findings for the Sequoyah facility related to the fire protection program, but did identify one audit recommendation and eight less significant implementation weaknesses and hardware items that were
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documented in Problem Evaluation Reports (PERs) or Work Requests (WR) in accordance with the' corrective action program.
The inspectors reviewed the fi'nal audit report and verified that the planned corrective actions in response to the identified recommendation issue was properly addressed and was acceptable. The inspectors concluded that the assessment of. the facility's fire protection program was comprehensive and effective in identifying fire protection program performance to management. The corrective actions in response to previously identified audit issues addressed in the licensee PER closure packages were good and had been implemented in a timely manner.
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- c. Conclusions l
The licensee's 1998 Nuclear Assurance assessment of the facility's fire protection program was comprehensive and effective in identifying fire protection program performance to management. The licensee corrective actions in response to previously identified audit issues were good and had been implemented in a timely manner.
F8 Miscellaneous Fire Protection issues F8.1' (Closed) VIO 50-327. 328/96-10-01/EA 96-269 01013. Inadeauate
, Identification and Resolution of Fire Protection Deficiencies. This l. violation included a total of eight issues. Section F8.3 of NRC Integrated Report 50-327. 328/97-03 identified that corrective actions had been completed and reviewed on four issues. The inspectors reviewed the remaining four issues (1.a.1.b.1.d. and 1.e during this inspection. Sections F2.1. F3.1, and F3.2 of this report identify the inspectors' review of these fire protection areas including the
' implementation of corrective actions for these four issues. During-this review.: the inspectors verified the corrective actions described in the i licensee *s response letter, dated December.19, 1996, to be reasonable l and complete. .No similar problems were-identified.
j~ lR1- Radiological. Protection and Chemistry (RP&C). Controls (83750)
R1.1 Radiological Protection' and Chemistry' Controls a. Insoection Scooe (83750~and 84750)
.The inspectors reviewed implementation of selected elements of the licensee's radiation protection program, The review included observation ~of radiological protection activities including personnel
. monitoring, radiological postings, high radiation area controls, and-verification of posted radiation dose rates, contamination controls within the radiologically controlled area (RCA),and container labeling.
In addition ALARA work planning, pre-job worker briefings, and job
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execution observations were performed. The inspectors also reviewed
! licensee records of personnel radiation exposure and discussed ALARA program details, implementation and goals. Requirements for these areas were specified in 10 CFR 20 and TSs.
!
! b. Observations and Findinas l The inspectors toured the health physics facilities. the auxiliary l building and outside Dry Active Waste Building. Records reviewed determined the licensee was tracking and trending personnel
! contamination events (PCRs). The licensee had tr6cked approximately 58 l PCRs for the 1998 fiscal year to date which included skin and clothing
!
contaminations. Radiologically controlled areas including radioactive
, material storage areas (RMSAs). High Rad Areas, and Locked High Rad i
Areas were appropriately posted and radioactive material was appropriately stored and labeled.
The inspectors reviewed operational and administrative controls for entering the RCA and performing work. These controls included the use of radiation work permits (RWPs) to be reviewed and understood by workers prior to entering the RCA. The inspectors reviewed selected RWPs for adequacy of the radiation protection requirements based on work scope, location, and conditions. For the RWPs reviewed, the inspectors noted that appropriate protective clothing, and dosimetry were required.
During tours of the plant, the inspectors observed the adherence of plant workers to the RWP requirements. The inspectors observed personal dosimetry was being worn in the appropriate location.
'
The inspectors reviewed the contamination control and health physics response to a medical emergency that occurred in the early morning hours of October 6. 1997 and reported as NRC Event 33034. The event was reported as required by 10 CFR 50.72(b) (2) (v) Offsite Medical and 10 CFR 50.72(b) (2) (vi) Offsite Notification. The event involved an individual transported offsite for medical assistance who was pronounced dead at the local hospital. The inspectors reviewed the job RWP 97-0-00016 00 00 " Plant System Filter Change-Out to include all associated work." The TVA NUCLEAR (TVAN) Safety and Health Manual and Work Order 97-10896-000 " Seal Water Injection Filter A".The inspectors reviewed the licensee's incident report, health physics job and personnel radiation surveys and personnel and job contamination surveys and determined that i contamination was controlled and doses to response personnel were appropriately controlled.
The inspectors discussed ALARA goals and annual exposures with licensee management and determined the organizational structure and responsibilities for the ALARA staff were clearly defined in
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organizational charts. The inspectors noted that 38 pre-job ALARA Planning Reports were prepared for the work activities that exceeded 1 person-rem and accounted for approximately 95% of the station exposure for FY 1997.
The inspectors observed workers properly using friskers at the exit locations from controlled areas. The inspectors observed workers properly exiting the protected area through the exit portal monitors.
The Fiscal Y & c 1998 site exposure goal was set at 399 person-rem. At the time of the inspection, the site person-rem was about 160.037 person-rem.
The inspectors reviewed the Contaminated Square Footage Data and observed that the licensee has reduced the area from a high in July 1990 of 14% to the present 0.75% in 1998. The licensee considers 326,522 square feet as the largest possible contaminated area (denominator).
The 0.75% represents about 2449 square feet.
The inspectors. reviewed the fiscal year generation of radwaste for the period 1991 to 6/20/98. The total generated is shown by the following table:
Fiscal Year Cubic Feet Generated 1991 55545 1992 58865 1993 27560 1994 21586 1995 17989 1996 17466 1997 *8139 1998 *1046 (as of 6/20/98)
Note: * This does not include the excavated contaminated soil and asphalt generated by the spills of May 19, 1997 (SO971429PER) 5500 cubic l feet and January 10, 1998 (SO980021PER) 2007 cubic feet.
The inspectors observed several tube pulls from one of sixty four (64)
removed used Lower Compartment Coolers located in the DAW building. The licensee was performing this work in support of the Metals Reclamation and Equipment Project. The inspectors observed contamination control, work area breathing air sample collection and personnel dosimetry and RWP adherence. This work project was undertaken to recover costs associated with copper scrap recovery and volume reduction disposal cost )
avoidance, l
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This reduction of the generation of radwaste demonstrates aggressive management.
c. Conclusions Radiological facility conditions in radioactive waste storage areas, health physics facilities and DAW Building were found appropriate anJ the areas were properly posted and material appropriately labeled. j Personnel dosimetry devices were appropriately worn. Radiation work ;
activities were appropriately planned. Radiation worker doses were I being maintained well below regulatory limits and the licensee was maintaining exposures ALARA. Health physics response to a medical emergency was appropriate. 1 R1.2 Transportation of Radioactive Materials i
a. Insoection Scooe (86750) i The inspectors evaluated the licensee's transportation of radioactive materials program for implementing the revised Department of l Transportation (DOT) and NRC transportation regulations for shipment of l
,
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radioactive materials as required by 10 CFR 71.5 and 49 CFR Parts 100 l through 177. '
!
b. Observations and Findinas The inspectors reviewed selected procedures and determined that they adequately aadressed the following: 1) assuring that the receiver has a i license to receive the material being shipped: 2) assigning the form.
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quantity type, and proper shipping name of the material to be shipped:
3) classifying waste destined for burial: 4) selecting the type of package required: 5) assuring that the radiation and contamination l l
limits were met: and 6) preparing shipping papers.
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The inspectors reviewed a sample of shipping papers and receipt surveys.
The inspectors determined that the shipping papers were complete and the '
shipping as well as the receipt surveys were complete and met the requirements. .
c. Conclusions
,
Based on the above reviews, the inspectors determined that the licensee
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had effectively implemented a program for shipping and receiving ;
radioactive materials as required by NRC and DOT regulations. '
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l R1.3 Water Chemistry Controls a. Insoection Scone (84750)
The inspectors reviewed implementation of selected elements of the licensee's water chemistry control program for monitoring primary and secondary water quality. The review included examination of program guidance and implementing procedures and analytical results for selected chemistry parameters.
b. Observations and Findinas The inspectors reviewed TSs. which described the operational and surveillance requirements for reactor coolant activity and chemistry, and Final Safety Analysis Report (FSAR), Section '0.3.5. Water Chemistry. The section indicated that guidelines for maintaining reactor coolant and feedwater quality were derived from vendor recommendations and the current revisions of the Electric Power Research Institute (EPRI) Pressurized Water Reactor (PWR) Primary and Secondary Water Chemistry Guidelines. The UFSAR also indicated that detailed operating specifications for the chemistry of those systems were
,
addressed in the Station Chemistry Section.
The inspectors reviewed selected analytical results recorded for Unit I and Unit 2 reactor coolant and secondary samples taken during the Inspection period. The selected parameters reviewed for primary chemistry included dissolved oxygen, chloride, fluoride, and sulfate levels. The selected parameters reviewed for secondary chemistry included hydrazine, iron, and copper levels. Those primary parameters reviewed were maintained well within the relevant TSs limits and within the EPRI guidelines for power operations.
The inspectors reviewed the U2C8 RF0 Primary Chemistry Shutdown and Startup Time Line and the upcoming UIC9 RF0 Primary Chemistry Recommendations. The report was detailed and enumerated the chemistry activities. The report provides a detailed roadmap to remove activated core corrosion crud. Shutdown chemistry controls during the U2C8 RF0 removed approximately 2215 Curies. The removal of core and ex-core crud significantly reduced general area radiation doses.
c. Conclusions
. Based on the above reviews, it was concluded that the licensee's water i
chemistry control program for monitoring primary and secondary water
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quality had been implemented, for those parameters reviewed, in accordance with the TSs requirements.
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f R2 -Status of Radiation Protection Facilities and Equipment j
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l R2.1 Radiation Monitor and Instrument Inseection a. Insoection Scooe (83750 and 84750)
l The Offsite Dose Calculation Manual requires the annual. submission of an l. Annual Environmental Operating Report.
L b. Observations and Findinas The inspectors reviewed the Annual Radiological Environmental Operating Report for the period January through December 31,1997.
i L Potential doses to maximum individuals and the population around the Sequoyah' Nuclear Plant were calculated for cach quarter as required by the Offsite Dose Calculation Manual (ODCM). The quarterly gamma radiation . level comparison between the site boundary and offsite stations were consistent with levels measured for preoneration and l _ construction. The dose to a member of the public was determined to be well below the 10'CFR 20 annual limit of 100 mrem. The inspectors also determined that the licensee complied with 40 CFR 190. The annual 40 CFR 190 limit is 25 mrem and the calculated dose was approximately l- 1.22E-1 mrem or <1%.
l E c. Conclusions The Total Dose from the 40 CFR 190 calculation for the radiological L impact from the facility operation was less than 1% of the regulatory l-
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iimit. The exposures calculated from the 1997 Annual Radioactive Effluent Release Report resultant data were consistent with previous results from the monitoring program and a small percentage of the 10 CFR 20 limits.
'R8 Miscellaneous RP&C Issues'(92904)
R8.1 (Closed) Insoector Follow-uo Item (IFI) 50-327.328/98-03-007: Review an Action Plan to Track and Reduce the Number of Contaminated Catch Basins.
The inspectors reviewed the corrective actions that have been implemented by the licensee to track and reduce the number of contaminated catch basins. The inspectors noted that the licensee had eliminated or.provided work orders to correct the problems that required contaminated catch basins. The action plan and tracking system at the time of the inspection accounted for all of the contaminated catch containers and a plan for their correction.
R8.2 (OPEN) IFI 50-327.328/98-03-008: Review the resolution of the survey mao aeneration data loss. The inspectors reviewed the corrective actions
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that have been implemented by the licensee for PER No. SQ980110PER. At the time of the inspection several key corrective actions remained to be-implemented and field tested. The corrective actions are scheduled to be completed by the end of July. This item will remain open.
V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee l
management at the conclusion of the inspection on July 17. 1998, and for region' based inspections on June 10 and July 12. 1998. The licensee acknowledged the findings presented.
During the inspection period, the inspectors asked the licensee whether
- - any materials would be considered proprietary. Proprietary information.
!
related to the pressurizer level instrument issue, was identified and will be returned to the licensee.
! PARTIAL-LIST OF PERSONS CONTACTED Licensee
- Bajestani M., Site Vice President
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- Burton, C.. Engineering and Support Systems Manager l Butterworth. H., Operations Manager l Gates. J., Site Support Manager l * Freeman. E. , Maintenance and Modifications Manager l Herron, J.. Plant Manager
- Kent. C.. Radcon/ Chemistry Manager L *Koehl. D... Assistant Plant Manager l
- Lorek. M., System Engineering Manager O'Brien. B., Maintenance Manager
~*Salas. P., Manager of Licensing and Industry Affairs
- Valente. J. , Engineering & Materials Manager
- Attended exit interview INSPECTION PROCEDURES USED l' -
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IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in Identifying Resolving and
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Preventing Problems IP 61726: Surveillance Observations IP 62706: Maintenance Rule IP 62707: Maintenance Observations IP 64704: Fire Protection Program IP 71707: Plant Operations
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! 36 IP 83750: Occupational Radiation Exposure IP 84750: Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP 92901: Followup - Operations IP 92902: Followup - Maintenance l IP 92903: Followup - Engineering IP 92904: Followup - Plant Support ITEMS OPENED. CLOSED. AND DISCUSSED Ooened TYDe Item Number Status Description and Reference VIO 50-328/98-07-01 Open Failure to Promptly Identify and Correct Plant Deficiencies as Required by 10 CFR 50. Appendix B (Section E1.1).
VIO 50-328/98-07-02 Open Failure to Perform a Valid Pressurizer Level Channel Calibration On Level Channel 2-LT-68-320 as Defined by TS 1.4 (Section E1.1). :
Closed i
Tvoe Item Number Status Description and Reference '
VIO 50-327/98-03-02 Closed Failure of Site Personnel to Initiate a PER After Analysis of the PRT Sample Indicated a High Oxygen Concentration (Section 08.1). l I
VIO ~50-327, 328/97-08-02 Closed Failure to Meet ASME Section XI Code i Testing Requirements (Section 08.2). I
IFI 50-328/97-17-03 Closed Water Hammer Failure of Heater Drain Flow Control Valve (Section M8.1).
URI 50-328/97-18-04 Closed Resolve Issues Related to Pressurizer Level Instrumentation (Section El.1).
VIO 50-327, 328/96-10-01 Closed Inadequate Identification and l EA 96-269 01013 Resolution of Fire Protection Deficiencies (Section F8.1),
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IFI 50-327. 328/98-03-07 Closed Review an Action Plan to Track and Reduce the Number of Contaminated Catch Basins (Section R8.1).
Discussed Typa item Number Status description and Reference URI 50-327/98-06-02 Discussed Potential Improper Corrective Maintenance Activities Related to Improper Breaker Contact Compression Setting and Inadequate Post Maintenance Testing (Section M2.1).
IFI 50-327, 328/98-03-08 Discussed Review the Resolution of the Survey Map Generation Data Loss (Section R8.2).
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Auxiliary Feedwater ALARA - As Low As Reasonably Achievable ASME -
American Society of Mechanical Engineers l CFR -
Code of Federal Regulations DCN -
Design Change Notice i DCR -
Design Change Request DG -
Diesel Generator DN -
Deficiency Notice DOT -
Department of Transportation EDG -
Emergency Diesel Generator E0P -
Emergency Operating Procedure ERCW - Essential Raw Cooling Water FCV -
Flow Control Valve FPR -
Fire Protection Report GL -
Generic Letter I&C -
Instrumentation and Control IFI -
Inspector Followup Item IR -
Inspection Report
LER -
Licensee Event Report MCC -
Motor Control Center MOAFW - Motor Driven Auxiliary Feedwater MI W -
Main Feedwater MFRV - Main Feedwater Regulating Valve MMG -
Mechanical Maintenance Group MRC -
Management Review Committee NA -
Not Applicable NDE -
Non-Destructive Examination NRC -
Nuclear Regulatory Commission '
NRR -
Nuclear Reactor Regulation NSSS - Nuclear Steam Supply System PER -
Problem Evaluation Report PM -
Predictive Maintenance PMT -
Post Maintenance Test GA -
Quality Assurance RCP~ -
Reactor Coolant Pump RHR -
Residual Heat Removal System SI -
Surveillance Instruction TDAFW - Turbine Driven Auxiliary Feedwater Pump TIA -
Technical Interface Agreement
-. TOE -
Technical Operability Evaluation l TS -
Technical Specifications TVA -
Tennessee Valley Authority TVAN -
Tennessee Valley Authority Nuclear i UFSAR - Updated Final Safety Analysis Report UPS -
Uninterruptable Power Supply URI -
Unresolved Item
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f uhq 4 UNITED STATES j
l g NUCLEAR REGULATM7 COMMISSION O f WASHINOTON. ,. 206 6 0001 July 14, 1998
%.....[
MEMORANDUM TO: Loren R. Plisco, Director l
Division of Reactor Projects Region Il FROM: Frederick J. Hebdon, Director Project Directorate 11-3 Division of Reactor Projects - 1/11
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f l j
Office of Nuclear Reactor Regulation SUBJECT: RESPONSE TO TASK INTERFACE AGREEMENT (TIA)98-002, SEQUOYAH UNIT 2, ACCEPTABILITY OF METHODOLOGY FOR CALIBRATION OF PRESSURIZER LEVEL INSTRUMENT (TAC NO.
MA1289) '
in a memorandum dated March 10,1998, Region Il requested NRR assistance in evaluating the acceptability of the Tennessee Valley Authority (TVA) methodology used to calibrate ;
pressurizer level instrument channel 2-LT-68-320 at the Sequoyah Nuclear Plant, Unit 2. l Specifically, Region 11 noted that, when this channel failed its calibration surveillance test during a refueling outage in October 1997, TVA performed a technical evaluation and declared the t
instrument to be " acceptable as-is" for operation based on margin in the accuracy calculation.
The NRR technical staff has reviewed the calculation documentation supplied with the Ti^ and i has come to the following conclusions: I 1. The licensee's calibration using redundant instrumentation was inadequate to confirm ,
the assumptions of the setpoint calculation; and, subsequently the Technical l Specification (TS) Allowable Value and Trip Setpoint were not satisfied.
2. The staff finds that the licensee's calibration without consideration of the setpoint methodology uncertainties and accuracies does not meet the TS definition of calibration.
3. The staff also finds that a calibration methodology using redundant instrumentation, as discussed in TIA Question 3, would not ensure that an Allowable Value of 92% was met.
- l 4. Although the licensee subsequently demonstrated thai sufficient margin was available to accommodate the uncertainty of the licensee's calibration methodology, the staff finds that the licensee's original determination that instrument 2-LT-68-320 remained operable was not justified based on TS requirements or the guidance of Generic Letter 91-18.
Shouid you have any additional questions, please call Mr. Ronald W. Hernan of my staff. This J memorandum closes out TAC No MA1289.
Docket No. 50-328 I
Attachment: TIA Evaluation
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cc w/ attachment: C. Hehl, Region I G. Grant, Region 111 L K. Perkins, Region IV _
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UNITED STATES
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NL; CLEAR REGULATORY COMMISSION WASHINGTON, o.C. 20555 4001 o'
%.++4 TASK INTERFACE AGREEMENT (98-002) EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION PRESSURIZER LEVEL INSTRUMENT CALIBRATION AND OPERABILITY TENNESSEE VALLEY AUTHORITY SEQUOYAH UNIT 2 DOCKET 50-328 1.0 INTRODUCTION By memorandum UIA) dated March 10,1998, Region 11 requested that NRR provide an evaluation of the Tennessee Valley Authority UVA) Sequoyah Unit 2 calibration methodology for Pressurizer High Level Trip Setpoint instrumentation. Additionally, the TIA requested that the staff evaluate the licensee's Technical Operability Evaluation (TOE) to ensure that the pressurizer levelinstrumentation met operability requirements. The TIA stated that the licensee's position is that although the pressurizer level inst.umentation failed to meet its "as-left" calibration surveillance criteria, the instrument remained operable "as-is" based on available margin in the uncertainty calculations.
The region requested NRR to respond to four questions related to the licensee's calibration practices and Technical Specification (TS) operability determination. The questions are listed below.
1. TVA indicated that they rescaled the instrument (LT-320) using the two other channels (LT-335 and LT-339). However, no documentation is available to justify how the rescaling in 1988 was performed. Is this acceptable considering the channels are independent? During the 1997 refueling outage, it was identified that both LT-335 and LT-339 had scaling errors.
is it acceptable to adjust one (or two) channel (s) to indicate / read the same as the one that is calibrated (however, with errors) and consider it to be calibrated?
2. The TS definition for channel calibration specifies that instrument channels be calibrated using a known source (scaling documents). Would this be considered a valid channel calibration? Is the licensee in violation of the TS for perfomaing channel calibration on LT-3207 '
3. TS 2.2.1 requires a pressurizer high level trip at 92% of the instrument span. All three instruments have errors between the scaling documents and the calibration procedures.
This causes a non-conservative errorin the calibration of the instruments and the instruments will not provide a trip signal until actual pressurizer level is above the TS Allowable Value of 92%. Does this meet TS 2.2.1 requirements for having a pressurizer high level trip at 92%7
- 4. Does the licensee's methodology for accepting the channel provide a sufficient basis for l operability?
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2.0 BACKGROUND During the Sequoyah Unit 2 refueling outage of October and November 1997 the inspectors noted that a pressurizer level instrument channel (2-LT-68-320) failed to meet its calibration surveillance requirements and that the licensee completed a TOE for the instrument. The evaluation by the licensee indicated that the instrument had failed to meet its "as-left" calibration for 3 points of a 9 point calibration. The licensee also noted that the instrument did not meet the manufacturer's specification for hysteresis or static pressure shift. Inconsistencies in the instrument scaling documents were also noted. The licensees evaluation determined that instrument 2-LT-68-320 met all TVA engineering requirements such that there was no loss of quality or functional capability. The licensee stated that this instrument was not found to be
" degraded" or "non-conforming" as defined by Generic Letter (GL) 91-18 Rev.1. The licensee defined " quality" as conformance to engineering requirements necessary for the channel to perform its intended function.
In October 1997, instrument 2-LT-68-32C was tested for a possible low pressure static shift based on previously documented errors found with this instrument. Transmitter 2-LT-68-320 could not be calibrated to within its "as-left" tolerance and a low pressure static shift was confirmed. A TOE was prepared by the licensee that concluded that 2-LT-68-320 met all engineering requirements such that there was no loss of quality or functional capability. The TOE acceptance was based in part on the transmitter out-of-tolerance condition being within available margin (100% of span). Scaling issues were also identified, but the licensee stated that they did not cause Emergency Operating Procedures (EOP) limits to be exceeded.
Subsequently, the licensee " calibrated" transmitter 2-LT-68-320 by using redundant channels of pressurizerlevelinstrumentation as a reference. The licensee considered this acceptable based on the observation that the transmitter error for 2-LT-68-320 would be within the allowances provided for in the accuracy calculations under pressurized conditions. The TOE stated that the allowance was within the acceptable deviation between channels.
3.0 EVALUATION l
The staff understands the lerm "rescaled" as used in Question 1 to indicate that instrument 2-LT-68-320 was essentially recalibrates using two redundant channels as a calibration {
reference. The practice of calibrating an instrument based on the calibration of redundant i
instmmentation is not accounted for in the licensee's calibration procedure or setpoint i methodology. The loop uncertainty using the above technique would be modified from that i
assumed for the setpoint. The licensee's evaluation of the uncertainties using redundant instrumentation as a calibration reference was performed after the fact and was not considered
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or available when the licensee "rescaled" instrument 2-LT-68-320. '
Section 2.2, " Limiting Safety System Settings," of the Sequoyah TS lists Functional Unit 11 as pressurizer water level high with a Trip Setpoint of <92% of instrument span with an Allowable Value of < 92.7% ofinstrument span. Section 2.2.1 states that:
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The reactor trip system instrumentation and interlocks setpoints shall be set consistent with the trip setpoint values shown in Table 2.2-1.
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AQIJOll-With a reactor trip system instrumentation or interlock setpoint less conservative than the value shown in the Allowable Value column of Table 2.2-1, declare the channel
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inoperable and apply the applicable Action statement requirement of Specification 3.3.1 l
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until the channelis restored to Operable status with its trip setpoint adjusted consistent
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with the trip setpoint value.
' . Table 3.3-1, " Reactor Trip System instrumentation" Functional Unit 11, " Pressurizer Water Level- High," Action #6 states: .
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I With the number of Operable channels one less than the Total Number of Channels,
STARTUP and/or Power Operation may proceed provided the following conditions are satisfied; a. The inoperable channelis placed in the trip condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
i b. The Minimum Channels Operable requirement is met: however, the inoperable l
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channel may be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surverance testing of other channels per specification 4.3.1.1.1.
Table 3.3-1 lists the Total No. of Channels for Functional Unit 11, " Pressurizer Water Level 7 - High" as 3 with the Minimum Channels Operable as 2.
l The failure of instrument 2-LT-68-320 to meet its calibration surveillance acceptance criteria with E the subseque'nt " calibration" of 2-LT-68-320 using redundant instrumentation did not satisfy the ;
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above LCO Actions for Allowable Value or Trip Setpoint. The " calibration" of 2-LT-68-320 using redundant instrumentation was not evaluated against the licensee's measurement and test ;
equipment criteria or the uncertainty assumptions of the setpoint methodology; and, as a result I cannot be considered a valid calibration of 2-LT-68-320 with respect to the Allowable Value or Trip Setpoint. '
l Additionally,10 CFR 50, Appendix B, Criterion XI states that:
A test program shall be established to assure that all testing required to demonstrate structures, systems, and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in applicable design documents. Test results shall be
documented and evaluated to assure that the test requirements have been satisfied.
Should the licensee fail to develop a test program specifically designed to use redundant instrumentation as calibration standards and fail to document the results of these tests then the licensee has not satisfied the requirements of Appendix B. This documentation would also include any variations in loop uncertainty budgets arising from using a calibration methodology that differs from that assumed in the plant setpoint documentation.
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The use of redundant instruments as calibration standards must also meet the requirements of 10 CFR 50, Appendix B, Criterion XII in that:
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Measures shall be established to assure that tools, gauges, instruments, and other l
measuring and testing devices used in activities affecting quality are properly controlled, '
calibrated, and adjusted at specified periods to maintain accuracy within necessary limits.
The use of a redundant instrument as a calibration standard is not supported by the licensee's j
setpoint methodology or the calibration definition in the Sequoyah TSs. '
Criterion 21 of 10 CFR 50, Appendix A states that:
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Redundancy and independence designed into the protection system shall be sufficient to assure that (1) no single failure results in a loss of the protective function and.... The prof.ection system shall be designed to permit periodic testing of its functioning when the reactor is in operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred.
The calibration of 2-LT-68-320 using redundant channels may put the redundancy and defense-in-depth designed into the system at risk.
.lEEE Standard 338,"lEEE Standard Criteria for the Periodic Surveillance Testing of Nuclear Power Generating Station Safety Systems," as endorsed by Regulatory Guide (RG) 1.118, provides design and operational criteria for the performance of periodic testing including the following definition of channel calibration:
Channel Calibration: The adjustment of channel output such that it responds, with acceptable range and accuracy, to known values of the parameter that the channel measures, and the performance of a functional test.
This definition is consistent with the Westinghouse Standard TS definition, which states in part:
A channel calibration shall be the adjustment, as necessary, of the channel so that it responds within the required range and accuracy to known input.
Calibration using redundant instrumentation without accounting for the additional uncertainty inherent in the calibration by redundant channels is not consistent with the above standard or the licensee's calibration acceptance criteria. The licensee failed to document these differences during the calibration of LT-320.
IEEE Standard 338 also states in Section 5, " Design Requirements," that provisions used for perturbing the same or substitute process variables are preferred over using simulated signals to verify overall tripping of each protective channel. Where perturbing the monitored variable or substitute is not practical, the proposed attemative tests shall have documented justification.
Section 6 of IEEE 338 also states that, "The operability of each redundant portion of the safety system shall be independently verified." For the performance of Channel Checks, IEEE 338 states that consideration shall be given to common mode failures when selecting channels for l comparison. Since the licensee did not document or independently verify the operability of each l
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redundant portion of the safety system or consider common mode failures cv using redundant instrumentation for the calibration of LT-320, the licensee did not meet the cr Mria of IEEE 338 or the guidance of RG 1.118.
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l 5 l Channel independence as stated in IEEE 279 states:
Channels that provide signals for the same protective function shall be independent and physically separated to accomplish decoupling the effects of unsafe environmental factors, electric transients, and physical accident consequences documented in the design basis, and to reduce the likelihood ofinteraction between channels during maintenance operations or in the event of a channel malfunction.
l Based on the above, the licensee's methodology did not ensure channelindependence per the requirements of 10 CFR 50.55a(h) (which re.fers to IEEE 279) by using redundant instrumentation as a calibration standard. Therefore, the licensees calibration method did not meet the requirements of 10 CFR 50.55a(h).
l The Standard TS define operability and refer to the capability to perform the "specified safety ,
function." GL 91-18 states that the specified function of the system is that safety function !
described in the current licensing basis for the facility. GL 91-18 also states that in addition to providing the specified safety function, a system is expected to perform as designed, tested, and maintained. If system capability is degraded to a point where it cannot perform with reasonable assurance or reliability, the system should be declared inoperable, even if at this instantaneous point in time the system could provide the specified safety function.
The TS provide a framework to ensure that a plant is operated per the assumptions of the design basis such that the safety analysis remains valid. Verification of system operability per TS !
requirements, including surveillance requirements, provides a means to demonstrate that a system is operable.
The licensee's surveillance of the LT-320 instrument, although indicating that the instrument remained functional, did not ensure that design margins or engineering margins were maintained.
Although a degraded condition was identified (pressure shift), corrective actions were not identified for the subject transmitter even though the transmitter was not performing as designed, or within the test and maintenance criteria defined for this instrument.
The licensee referenced WCAP-1 1239, Revision 4, Figure 4-1 as depicting the methodology for 1 application ofinstrument errors to the Trip Setpoint, A:lowable Value and Safety Analysis Limit. !
The licensee stated that this figure defines the Allowable Value as the Trip Setpoint plus rack drift. The staff notes that Figure 4-1 references the NUREG-0452 setpoint error breakdown and not the methodology used by Westinghouse. The Allowable Value to Trip Setpoint error breakdown is defined as either Ti and T2 not strictly " rack drift"in the Westinghouse setpoint methodology. Therefore, the licensee reference to Figure 4-1 is an incorrect reference with regards to the licensee's setpoint methodology error breakdown. ;
5.0 CONCLUSION Based on the above, the staff finds that the licensee's calibration of LT-320 using redundant instrumentation did not account for revised channel uncertainties and, therefore, was not in agreement with the assumptions of the setpoint methodology orinstrument uncertainty I
calculations. Although the licensee provided a revised evaluation of setpoint uncertainties based on calibration to redundant instrumentation, this evaluation was not performed as part of the original TOE or calibration.
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With regard to the specific questions included in TIA 98-002, the staff has the following response to TIA Question 1; the staff finds that the licensee's calibration using redundant instrumentation was inadequate to confirm the assumptions of the setpoint calculation and subsequently the TS Allowable Value and Trip Setpoint were not satisfied. With regard to TIA Question 2, the staff finds that the licensee's calibration without consideration of the setpoint methodology uncertainties and accuracies does not meet the TS definition of calibration. The staff also finds that a calibration methodology using redundant instrumentation, as discussed in TIA Question 3, would not ensure that an Allowable Value of 92% was met. Finally, with regard to TIA Question
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' 4, although the licensee subsequently demonstrated that sufficient margin was available to
- accommodate the uncertainty of the licensee's calibration methodology, the staff finds that the licensee's determination that instrument 2-LT-68-320 remained operable was not justified based
- on TS requirements or the guidance of GL 91-18.
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