IR 05000395/1997011
| ML20211K546 | |
| Person / Time | |
|---|---|
| Site: | Summer  |
| Issue date: | 10/02/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20211K524 | List: |
| References | |
| 50-395-97-11, NUDOCS 9710090269 | |
| Download: ML20211K546 (25) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No.:
50-395 License No.-
NPF-12 Report No.-
50-395/97-11 Licensee:
South Carolina Electric & Gas (SCE&G)
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Facility:
V. C. Summer Nuclear Station Location:
P. O. Box 88 Jenkinsville. SC 29065 Dates:
July 27 - September 6, 1997 Inspectors:
B. Bonser. Senior Resident Inspector (SRI)
T. Farnholtz. Resident Inspector R. Aiello. Reactor Inspector. RII (Section 01.1. 02.1. M1.1.
and M2.1)
P. Hopkins. Project Engineer. RII (Section 01.1. 02.1 M1.1.
and M2.1)
R. Freudenberger. SRI - Catawba. RII (Section 08.1.
08.2 M8.1. M8.2 M8.3. and R8.1)
P. Fillion. Reactor Inspector. RII (Section E7.2 E8.2 and E8.4)
J. York. Reactor Inspector. RII (Section E7.2 and E8.3)
Approved by:
G. 6elisle. Chief Reactor Projects Branch 5 Division of Reactor Projects s
Enclosure 2
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EXECUTIVE SUMMARY V. C. Sunmer Nuclear. Station NRC Integrated Inspection Report No. 50-395/97-11 This integrated inspection included aspects of licensee operations.
maintenance, engineering. and plant support.
The report covers a 6-week period of resident ins)ection; in addition. it includes the results of announced inspections )y regional inspectors.
Doerations The conduct of operations was professional and safety conscious.
- Improvements were noted in the control room and in the conduct of operations in the control room (Section 01.1).
The compensatory actions in place following the identification of a
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design deficiency in the diesel generator building ventilation system fan control circuit were adequate.
All design basis functions of this system were met with supalementary instructions contained on caution tags placed on each of tie four fan control switches (Section 01.2).
A modification to replace Den type recorders with digital recorders will
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increase the accuracy of t1e diesel generator output recorders (Section 02.1).
i The licensee took appropriate action to identify and stop a source of
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increased reactor coolant system unidentified leakage in the Auxiliary Building (Section 02.2).
A walkdown of accessible portions of the A train and 8 train Control
Room Ventilation Systems identified no concerns (Section 02.3).
The knowledge level and performance of the Intermediate Building
Operator was good.
The observed touring and log recording techniques were effective to ensure that potential equipment problems were identified (Section 04.1).
Maintenance All obsersed maintenance tasks were conducted in a competent and
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professional manner.
Appropriate tools. equipment. and procedures were used.
Proper radiological controls were utilized when required (Section M1.1).
A freeze seal was installed using existino procedural guidance.
The
freeze seal melted.
The licensee is reviewing the lessons learned from this event to enhance their freeze seal program (Section M1.2).
Observed surveillance tests were performed satisfactorily and in
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accordance with applicable procedures.
Crew briefi_ngs prior to performance of Surveillance Test Procedures were done well by the Shift Superviwr. Control Room Supervisor and radiation protection personnel.
(Section M2.0.
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The licensee's program to test a representative sample of safety-related
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snubbers as required by Technical Specification (TS) was adequate.
In addition the licensee's program to reduce the total population of snubbers in the plant was acce) table.
The licensee exhibited conservative decision making w1en additional snubbers were selected to be tested following several snubber test failures.
An inspection followup item was opened to followup on the licensee's efforts to determine the cause and corrective actions of degraded snubber conditions (Section M2.2).
The licensee demonstrated conservative decision making by entering
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TS 3.0.3 in response to the identification of incorrect time constants E
in the OT delta T and OP delta T reactor trip setpoints.
A violation
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was identified for failure to maintain the calibration procedures to ensure correct setting of the OT delta T and OP delta T reactor trip setpoints (Section M3.1).
A non-cited violation was identified for an inadequate shutdown margin
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procedure to determine shutdown margin for a stuck rod.
The inspectors concluded that the licensee had taken adequate corrective action (Section M3.2).
Enaineerina A violation was identified concerning the failure to install a react '
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make-up water line guard pipe as shown on the applicable plant draungs.
The guard pipe acted as a spray shield to protect essential components in the vicinity of the make-up water line. A discrepancy in the terminology used between the Final Safety Analysis Report and the plant drawings was identified (Section E1.1).
The licensee established adequate controls for use of the Leading Edge
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Flow Meter to prevent the plant operating above the licensed thermal limit (Section E2.1).
Inspectors reviewed 2 of the licensee's 11 SSFIs and concluded that they
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were detailed inspections, broad in scope and performed by competent individuals.
Findings had been resolved in a timely manner and generic implications were addressed (Section E7.2).
Plant Support Radiological controls and conditions observed during the conduct of
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tours were found to be acceptable (Section R1.1).
The inspectors observed security activities including compersatory
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measures during the conduct of plant tours and plant activities and found them to be acceptable (Section S1.1).
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Report Details Summary of Plant Status
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Unit 1 began this inspection period at 100 percent power and remained at that level for the entire inspection period.
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Operations l
Conduct of Operations 01.1 Daily Plant Status Reviews a.
Insoection Scoce (71707)
The inspectors conducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain awareness of overall facility operations and reviewed operator logs to verify operational safety and compliance with Technical Specifications (TSs).
Instrumentation and safety system lineups were periodically reviewed from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status and housekeeping.
Condition Evaluation Reports (CERs) were reviewed to assure that potential safety concerns were properly reported and resolved.
b.
Observations and Findinas The inspectors found that daily operations were generally conducted in accordance with regulatory requirements and plant procedures.
Good equipment material conditions were also evident by extended problem-free plant operation.
Human performance errors and weaknesses in operating practices were not identified.
The control room recarpeting, new furniture, and new uniforms worn by operational personnel were identified as a marked human factors improvement.
These improvements appear to add to the professionalism in operations.
The remodeling and relocation of the tagging and work control center desk has im] roved control room access control.
The tagging and work control des ( is now equipped with " state of the vt" equipment such as a portable telephone, a new copy machine, and a high speed computer capable of tagging and reference material retrieval.
c.
Conclusions The conduct of operations was professional and safety conscious.
Improvements were noted in the control room and in the conduct of operations in the control room.
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01.2. Diesel Generator (DG) Buildino Ventilation Control Switch 00eration-
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Insoection Scooe (71707)
l The inspectors reviewed an Operator Workaround concerning a DG building i
ventilation control switch operation design deficiency.
The inspectors reviewed the licensee's compensatory actions and the design basis functions of this system as described in the Final Safety Analysis Report (FSAR).
b.
Observations and Findinas On July 30, 1996, the licensee identified a condition where the breaker that feeds one of four DG ventilation fans tripped open when the control switch was repositioned from START to AUTO.
Engineering personnel performed an evaluation that determined this phenomenon was due to a design oversight which failed to recognize the conditions that set up an inappropriate sequence for contact actuation between contacts in the selector switch and contacts on the damaer unit. A )lant modification to correct this problem was planned to 3e completed )y December 1997.
The inspectors reviewed the FSAR description of the DG building ventilation system (FSAR Section 9.4.7.2.1).
The purpose of the fans is to maintain acceptable conditions in the OG rooms and associated electric equipment roonc. While in automatic. these fans cycle on and off under the control of a thermostat located in the DG room when the DGs are not operating. Also, the fans automatically start if the associated DG starts.
In addition, the system provides a means to manually operate the fans from the control room and also to provide various alarm and indication functions.
To compensate for the design deficiency, operations personnel attached a yellow CAUTION tag to each of the four DG fan control switches on the Heating. Ventilation and Air Conditioning (HVAC) board in the control room.
The instructions on these tags state " Remain in AUTO to prevent breaker trip.
If run in START check / reset breaker when returned to AUTO."
The inspectors concluded that the licensee's compensatory actions should ensure operation of the DG HVAC system as designed.
C-Conclo: ions
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The compensatory actions in ) lace following the identification of a design deficiency in the DG ]uilding ventilation system fan control circuit were adequate.
All design basis functions of this system were met with supplementary instructions contained on caution tags placed on each of the four fan control switches.
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02 Operational Status of Facilities and Equipment j
02.1 Control Room Chart Recorders (71707)
On August 13. the inspectors checked the control room chart recorders to assure that pens were marking properly and the recorders were timing correctly.
The inspectors also verified that each chart had been checked by each shift and annotated as required by procedures.
A modification will replace the DG output recorders with " state of the art" digital recorders in the control rocu.
This modification will increase the accuracy of the DG output recorders.
02.2 Recctor Coolant System (RCS) Unidentified Leakaae
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InsDeCtion Scooe (71707)
TF inspectors reviewed the status of RCS unidentified leakage.
b.
Observations and Findinas On August 17. during a review of the control room logs, the inspectors observed that unidentified RCS leakage had trended up from about 0.25 gpm in early August to about 0.4 gpm.
The inspectors * review of control room instrumentation-and trends did not indicate that the increased leakage was in containment.
The inspectors concluded that this increased leakage was probably in the Auxiliary Building.
On August 20.
an Auxiliary Building Operator identified leakaae from the outboard seal on the A Centrifugal Charging Pump (CCP). The licensee replaced the seal on the CCP and RCS unidentified leakage appeared to trend back to the original amount. The inspectors were satisfied that the licensee had takcn appropriate action to identify and stop a source of increased RCS unidentified leakage.
c.
Conclusions The licensee took appro]riate action to identify and stop a source of increased unidentified RCS leakage in the Auxiliary Building.
02.3 Enqineered Safety Feature System Walkdown (71707)
The inspectors performed a walkdown of the accessible portions of the A train and B train Control Room Ventilation Systems.
No discrepancies or concerns were identified.
Operator Knowledge and Performance 04.1 Intermediate Buildina 00erator Rounds
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Insoection Scoce (71707)
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The inspectors accompanied the Intermediate Building Operator during the performance of a routine tour and TS required log taking, b.
Observations and Findings
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The inspectors observed the routine activities of the Intermediate Building Operator which included a complete tour of the assigned spaces and the recording of logs. Areas toured included the 1DA and 10B
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switchgear rooms the reactor control rod equipment room, the control room evacuation panel rooms the DG rooms, the main steam isolation valve area, and ventilation equipment areas. Also included were the
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Service Water (SW) building. and the fire pump and circulating water pump areas.
The operator toured these areas in a systematic manner and inspected all areas.
Logs were recorded on a handheld electronic device which was later downloaded into a computer for storage and reviewing and to ensure that potential equipment problems were identified.
The operator demonstrated a good level of knowledge and familiarity with his duties and responsibilities.
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Conclusions E
The inspectors considered the knowledge level and performance of the Intermediate Building Operator was good.
The observed touring and log recording techniques were effective to ensure that potential equipment problems were identified.
Hiscellaneous Operations Issues (92901)
08.1 (Closed) Inspection Followuo Item 50-395/96001-01:
partially submerged tendon inspection.
This issue involved the lowest containment tendon end cover in the auxiliary building containment tendon sump that was found partially submerged by standing water.
The licensee pumped the water from the area and planned an inspection of the tendon end cover during the spring 1996 refueling outage.
The item was opened pending the inspectors' verification that the inspection was performed during
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the outage and review of the data.
The inspectors reviewed data sheets
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from the inspection of the affected tendon, performed on April 6. 1996.
No water had entered the tendon can and no other degradation was identi fied.
In addition, the inspectors verified that the containment tendon sump was free of standing water.
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08.2 (Closed) Licensee Event Reoort (LER) 50-395/96-02:
voluntary entry into TS 3.0.3.
This LER addressed a voluntary entry into TS 3.0.3 in order to restore the A train of the chilled water system to an operable status following an equiament problem on the A chiller.
The TS 3.0.3 entry occurred during t1e realignment of the C chiller to the A train because
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the B train was inoperable during a portion of the realignment.
This issue was previously evaluated by the NRC as documented in NRC Inspection Report No. 50-395/96001. Section 2.5.
The inspectors concluded that the licensee's decision to realign the chillers and enter
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TS 3.0.3 was conservative and a safety benefit, inere were no corrective actions necessary for this LER.
II.
Maintenance M1 Conduct of Maintenance M1.1 General Commenti a.
Insoection Scooe (62707)
The inspectors observed all or portions of the following work activities.
l MWR 9714942. Repair Slow Moving Valve
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MWR 9714258. Train B RB Spray Pump 7.2Kv Breaker Preventive
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Maintenance.
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MWP,9714107. Meggar B RB Spray Pump Motor to Determine
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Polarization Index.
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Observations and Findinas The inspectors found the work performed under these activities was professional and thorough. All of the work observed was performed with the work package present and in use.
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Conclusions All observed maintenance tasks were conducted in a competent and professional manner.
Appropriate tocls, equipment, and procedures were used.
Proper radiological controls were utilized when required.
M1.2 Freeze Seal On Residual Heat Removal (RHR) System Drain Valy_q
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Insoection Scoce (62707)
On August 5. the inspectors < ] served a portion of a drain valve (XVT087298-RH) replacement on the suction side of the B train RHR system pump (MWR 9709366).
b.
Observations and Findinas To replace a drain valve on the suction side of the B train RHR pump. a freeze seal was used on the 3/4-inch drain line to preclude draining the RHR piping.
The work involved cutting out the leaking drain valve and welding in a new valve. While welding in the new valve, the freeze seal melted and a leak resulted from the partial weld.
The suction and discharge side of the RHR pump had been isolated so potential leakage was limited to water contained in the piping between the isolation
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valves and this low point drain.
The leak was stoaped before any significant leakage occurred.
After a review of t1e problem by maintenance suaervision and a briefing of the work crew, a freeze seal was reestablisled and work continued to replace the drain valve.
The inspectors reviewed the engineering evaluation in sup) ort of the freeze seal installation on safety-related Jiping and Meclanical Mainten6nce Procedure (MMP) MMP-105.001. " reeze Seals On Stainless and Carbon Steel Pipe." Revision 6.
The inspectors concluded that the freeze seal procedural and engineering guidance was adequate and the seal was installed in accordance with this guidance.
In addition to the general procedural guidance )rovided in MMP-105.001 the application of carbon dioxide to maintain t1e seal was based on the experience and training of the technicians.
The inspectors concluded that the tect.nicians had underestimated the effects of the weld heat and had not injected sufficient carbon dioxide to maintain the seal.
The licensee is reviewing the lessons learned from this event to enhance their freeze seal program.
The loss of the freeze seal resulted in returning B train RHR to service later than planned but within the Limiting Conditions for Operation (LCO) limit. A fill and vent was also required of a portion of the B train RHR system before it could be returned to service.
The purpose of the freeze seal had been to avoid filling and venting this portion of the RHR system.
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Conclusions A freeze seal was installed using existing procedural guidance.
The freeze seal melted.
The licensee is reviewing the lessons learned from this event to enhance their freeze seal program.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Surveillance Observation a.
Insoection Scone (61726)
The inspectors observed and reviewed surveillance testing activities.
The inspectors observed all or portions of the following surveillance tests:
i STP-114.002. " Operational Leak Test." Revision 9
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STP-126.002. " Spent Fuel Pool Ventilation Operability Test."
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Revision 3
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STP-125.002. " Diesel Generator Operability Test." Revision 17
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STP-102.002. "NIS Power Heat Range Balance." Revision 7
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STP-105-016. " Charging Pump and Diesel Generator Slave Relay
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Testing." Revision 7 STP-223 002A, " Service Water Pump Operability Test," Revision 6
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STP-114-003. "RCS Leak Dilution Tests," Revision 1
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STP-121.002. " Main Steam Valves Operability Tests." Revision 10
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Observations and Findinas
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The inspectors found that the work performed under these activities was l
professional and thorough.
All of the surveillances observed were
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performed with the procedure present and in use.
The inspectors observed a strong awareness of plant material conditions during Surveillance Test Procedure (STP) preparation briefings.
Crew briefings prior to performance of STPs were done well by the Shift Supervisor, Control Room Supervisor, and radiation protection personnel.
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Conclusions l'
The observed surveillance tests were performed satisfactorily and in accordance with applicable procedures.
Crew briefings prior to performance of STPs were done well by the Shift Supervisor, Control Room Supervisor, arid radiation protection personnel, M2.2 Snubber Reduction and Testina Programs a.
Insoection Scooe (62707 The inspectors reviewed the licensee's activities concerning the ongoing snubber reduction program and the TS required snubber surveillance testing program.
The licensee identified an unusually high number of degraded snubbers during the performance of these programs.
The scope and performance of the TS required snubber testing program was reviewed for compliance with TS 4.7.7 b.
Observations and Findinas The licensee was conducting two snubber related programs concurrently during the inspection period.
The programs included a snubber reduction program which either removed snubbers entirely from plant systems or replaced them with rigid struts, and a TS required 18-month snubber surveillance testing program.
All snubbers were mechanical snubbers.
To satisfy the 18-month surveillance testing regirements of TS 4.7.7.e.
the licensee generated a list of 37 snubbers to ue removed and tested from safety-related systems.
The representative sample was randomly generated to reflect the same population percentages of small (Pacific Scientific Arrestor (PSA)-1/4 and 1/2). medium (PSA-1. 3 and 10), and large (PSA-35 and 100) snubbers.
Each of the selected snubbers was to s
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be functionally. tested on a bench testing device and-the results compared to the functional test acceptance criteria contained in TS 4.7.7.f. -In the event of a valid test failure, the sample of snubbers required to be tested would be increased as described in TS 4.7.7.e and a functional test failure analysis would be performed in accordance with TS 4.7.7.g.
The licensee was also engaged in a snubber reduction program.
The purpose of this program was to reduce the total population of snubbers
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in the plant so-as to-reduce the testing requirements and increase the overall reliability of the restraints used throughout the plant. A total of 366 snubbers was )lanned to be removed entirely from plant
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systems.
Another 435 snub)ers were planned to be removed and replaced with rigid struts-(54 percent of the 801 total snubbers included in the
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program).
As each PSA-1/4. 1/2, 1. and 3 snubber was removed, a freedom of motion test was performed to ensure that the snubber was free to move in both directions under force exerted by hand.
The larger PSA-10, 35, and 100 snubbers were bench tested upon removal.
In the event of a-failure of the freedom of motion test or bench test, a CER was written an an evaluation of the associated system operability was performed.
A total of 11 snubbers were ccmmon to both the surveillance testing program and to the reduction program.
This overlap was due to the random generation of the 37 snubbers selected to be tested.
The 11
- common snubbers were to be removed and eight were to be replaced with rigid struts.
At the end of the inspection period the licensee had identified seven degraded snubbers following freedom of motion tests conducted under the snubber reduction program.
In addition, one snubber, a PSA-3 snubber (MK-SWH-0103) installed in the SW system and included in both programs, failed the functional test.
The licensee determirad that this functional test failure was an invalid failure because the snubber had been hand stroked for a freedom of motion test under the snubber reduction program.
During the freedom of motion test, the snubber had been bottomed out and topped out at the extreme ends of its travel which could damage the snubber and cause a failure of the bench functional test. Also, the hand stroke was considered areconditioning which would invalidate the as-found condition of the snu]ber. As a result of this invalid TS surveillance test failure, the sample size was not increased.
The inspectors discussed the licensee's snubber reduction and testing program with members of the Office of Nuclear Reactor Regulation (NRR).
" w d on these discussions, it was determined that failures in the snubber reduction program did not require enlarging the samale size for the TS surveillance program.
Based on these discussions, t1e inspectors considered that the licensee's programs met regulatory requirements.
The inspectors also agreed that the test failure of the MK-SWH-0103 snubber was invalid for the reasons given.
Although the TS. surveillance testing sam)le size was not increased as a result of the SW snubber test failure, t1e licensee identified a total of 16 snubbers outside both the TS testing program and the snubber
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reduction program to be functionally bench tested to determine if other similar snubbers exhibited degraded conditions.
Eight of these snubbers are located in the Intermediate Building and the other eight are in the pressurizer cubicle of the Reactor Building.
The inspectors considered this testing effort for the snubber reduction arogram to be an example of conservative decision making to determine t1e extent of a possible degraded condition.
The seven degraded snubbers under the snubber reduction program were examined in an attempt to determine the cause of the degradation.
This examination resulted in some evidence of foreign material contaminated grease in the snubber internals which affected the moving parts.
The amount of contaminated grease was extremely small in each snubber and the licensee was sending these samples to an off site laboratory for i
analysis. The source of the contamination and the extent of the problem was not known at the close of the ins)ection period.
In an effort to determine the scope of the problem, t1e licensee expanded the snubber reduction program testing requirements from only freedom of motion testing to functional bench testing of all snubbers removed under this program.
In addition. 29 previously removed snubbers were disassembled and inspected and 43 previously removed snubbers were bench tested.
Some evidence of degraded conditions were identified from these examinations and tests. At the conclusion of the inspection period, the licensee was continuing to gather data in an attemat to determine the cause and corrective actions for the degraded snubaer conditions.
This effort will be followed and tracked as an Inspection Followup Item (IFI)
50-395/97011-01.
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Conclusions The licensee's program to test a representative sample of safety-related snubbers as required by TS was adequate.
In addition, the licensee's program to reduce the total Joaulation of snubbers in the plant was acceptable.
The licensee ex1iaited conservative decision making when additional snubbers were selected to be tested following the identification of several degraded snubbers.
An IFI was opened to followup on the licensee's efforts to determine the cause and corrective actions of degraded snubber conditions.
M3 Maintenance Procedures and Documentation
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M3.1 Over Temoerature Delta Temoerature Time Constants a.
Inspection Scooe (61726)
The inspectors reviewed the licensee's entry into TS 3.0.3 and the setting of Overtemperature delta Temperature (OT delta T) and Overpower delta Temperature (OP delta T) reactor trip time constants.
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Observations and Findinas
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On August 17. at 1:20 p.m., the licensee entered TS 3.0.3 when it was identified that time constants in the OT delta T reactor trip setpoint channels were set nonconservatively and the OT delta T reactor trip setpoints in all three RCS loops may not meet the Allowable Value given in TS.
TS 2.2.1.b. Limiting Safety System Settings Reactor Trip System Instrumentation Setpoints, states, in part, that with the reactor trip system instrumentation setpoint less conservative than the value shown in the Allowable Values declare the channel inoperable and apply the applicable Action statement requirements of TS 3.3.1.
At the time the licensee was unable to accurately determine if the trip setpoints could meet the Allowable Values.
The licensee entered TS 3.0.3 based on the conclusion that all three OT delta T channels did not meet the TS Allowable Value and were inoperable.
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During a routine review of an operational test procedure, the licensee identified that loop calibration procedures listed incorrect error tolerances for the OT delta T reactor trip setpoint channel lead / lag time constants.
These calibration procedures include STP-345.001.
" Delta T-TAVG Protection Loop 1 Calibration." Revision 8: STP-345.002.
" Delta T-TAVG Protection Loop 2 Calibration." Revision 8: and STP-345.003. " Delta T-TAVG Protection Loop 3 Calibration." Revision 9.
The calibrations are required to be completed at least once every 18 months and are normally performed during a refueling outage.
The licensee subsequently identified that the error tolerance for the OP delta T time constant in the same calibration procedures was also incorrect.
The lead / lag time constants provide dynamic compensation of the OT delta T and OP delta T reactor trip setpoints.
TS 2.2.1. Table 2.2-1 requires that the OT delta T lag time constant be set at 5 4 seconds and the lead time constant be set at 2 28 seconds.
The TS also requires the OP delta T time constant be set at 2 10 seconds.
The licensee's calibration procedures allowed the time constants to be set at 10 percent of the designated TS values.
/. review of the calibiation procedures completed during the last refueling outage in April 1996 found that in each of the three OT delta T loops and in one of the OP delta T loops a time constant was set incorrectly.
For OT delta T in loop 1. the 4 second time constant was set at 4.1 seconds: in loop 2. the 28 second time constant was set at 27.3 seconds; and in loop 3. the 4 second time constant was set at 4.2 seconds.
In the OP delta T loops, one of the time constants was set less than 10 seconds.
The licensee took corrective action immediately to restore the time constants to their proper settings and exit TS 3.0.3.
TS 3.0.3 was exited at 2:45 p.m. on August 17 when two of the three channels were corrected.
The purpose of the OT delta T reactor trip set point is to prevent the core from reaching a Departure from Nucleate Boiling (DNB) condition.
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reactor trip setpoint is continuously and separately calculated-for each of the'three RCS loops.
In the protection system, the indicated loop delta T is used as a measure of reactor power and is compared with a setpoint that is automatically varied, depending on Tavg. pressurizer
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pressure, and axial flux difference.
If the actual loop temperature difference exceeds-the loop setpoint, an OT delta T trip signal exists for that loop, If two of three loops exceed their setpoint, a reactor
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trip occurs. The OP delta T reactor trip is designed to protect against a high fuel rod power density and subsequent fuel rod cladding failure.
The inspectors reviewed the licensee's setpoint bases document.
The document stated that for OT delta T/0P delta T. Westinghouse models dynamic functions in the safety analyses with n: allowances for deviation from the nominal value for the time constants.
The document further stated that this implies the time constants must be verified to
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be set conservatively with respect to the values noted in the plant 1S.
- l Thus for lead / lag modules, the calibration "as left" condition must be increasing leads and decreasing lags (i.e. a nominal lead / lag of 50/5 j
may be left at 51/4.9, but not at 49/5.1).
The OT delta T/0P delta T time constants were revised in a TS amendment-
i dated October 1988 for the introduction of Vantage 5 fuel.
Prior to the
TS revision, the time constants were specified as exact values. A ten percent tolerance on the time constant settings was included in the calibration procedure because it was unreasonable to expect the time
'
constants to be. set exactly.
The TS amendment revised the time constants and used an inequality to indicate a conservative direction in
'
which to set them.
Westinghouse performed a qualitative safety evaluation of the condition identified by the licensee on August 17.
The Westinghouse evaluation
.
stated that key parameters used in safety analyses are typically assumed
'
to be at nominal design values.
Selected key parameters which are determined to be important to the. analysis results are identified and
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the values used in the analyses for these Jarameters are set in a
-
conservative fashion to demonstrate that tie ap)licable safety criteria are met.
It was Westinghouse's position that t1eir method yields a sufficiently conservative lice;,ing basis. and it was not necessary for each individual parameter to P conservative.
The safety evaluation
.
concluded that any penalty incurced due to the time constants being set in the nonconservative direction relative to the analysis value would be-easily offset by the conservatism applied to the-key analysis
'
parameters, which included uncertainties in the overall protection system setpoint channels. Westinghouse also stated that based on the results of a quantitative evaluation of time constants performed for an other plant, it was expected that in the worst case the impact of assuming explicit-tolerances of 110 on the Summer time constants would result in only a small DNB penalty, even when no consideration is given to the conservatism applied to other analysis parameters. A review of thermal-hydraulic calculations by Westinghouse for all reloads since the
'
,
-12 introduction of Vantage 5 fuel-showed that-there had always been sufficient DNB design margin available to offset any expected small penalty.
The inspectors concluded from their review of the Westinghouse analysis that setting the OT delta T/0P delta T time constants nonconservatively had a minor impact on safety margins.
The licensee, however, failed to appropriately implement a TS amendment in 1988 by correctly revising the implementing surveillance test procedures.
The inspectors also found that these caliLration procedures had been revised several times since the time constant revisions.
The procedure reviews had not identified the time constant discrepancies.
The failure to maintain the delt) T-TAVG protection loop-calibration procedures to ensure correct calibration of the reactor protection loops is identified as a Violation (VIO).
This is identified as VIO 50-395/97011-02.
c.
Conclusions The licensee demonstrated conservative decision making by entering TS 3.0.3 in response to the identification of incorrect time constants in the OT delta T and OP delta T reactor trip set points. A VIO was identified for failure to maintain the calibration procedures to ensure correct setting of the OT delta T and OP delta T reactor trip setpoints.
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M3.2 Shutdown Marain Verification Surveillance (61726)
,
a.
Insoection Scope (61726)
!
The inspectors reviewed the shutdown margin calculation procedure for verification of adequate shutdown margin with an immovable control rod.
b.
Observations and Findinas On August 6, the licensee identified that the shutdown margin verification procedure STP-134.001
" Shutdown Margin Verification,"
Revision 8, was not correct for verification of shutdown margin in Modes 1 and 2 with a possible immovable or untrippable control rod (s). The shutdown margin calculation determines the instantaneous amount of reactivity by which the reactor is subcritical or would be subtritical from its present condition assuming all full length rod cluster assemblies are fully inserted except for the single rod cluster assembly of highest reactivity worth which is assumed to be fully withdrawn.
In this case, a rod (s) could be untrippable and the rod of highest reactivity worth would also be assumed to be fully withdrawn.
TS surveillance requirement 4.1.1.1.1.a. " Shutdown Margin - Modes 1 and 2." states that with immovable or untrippable control rod (s). within one hour verify an acceptable shutdown margin with an increased allowance for the withdrawn worth of the immovable or untrippable control rod (s).
The shutdown margin verification calculation in STP-134.001 used a 1000 pcm allowance for each untrippable control rod.
The licensee identified that 1000 pcm was not sufficient for each immovable rod for the current
- _ _ _ _ _ _ _ _ _
_
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cycle core design.
In Modes 1 and 2 there was insufficient excess shutdown margin in the design to accommodate an actual stuck rod and the assumed rod of highest reactivity worth.
i TS 3.1.3.1.a. " Movable Control Assemblies " requires that with an immovable control rod the shutdown margin requirements of TS 3.1.1.1.
" Shutdown Margin - Modes 1 and 2." be saticfied within one hour and the plant to be in hot standby within six hours.
If a stuck rod actually occurred the licensee would follow the action statement of TS 3.1.1.1 for a shutdown margin less than the required 1.77 percent delta k/k which requires immediate boration at equal to or greater than 30 gpm of a solution containing greater than or equal to 7000 ppm boron.
The inspectors reviewed the licensee's corrective action in response to
!
this issue.
Prior to the beginning of the current operating cycle.
'
neither reactor engineering or operations personnel determined the reactivity allowance for an untrippable rod and did not recognize the need to update the shutdown margin procedure to reflect current core design.
The licensee revised STP-134.001 when this concern was identified to require the action statement of TS 3.1.1.1 be immediately applied to borate the RCS to meet the shutdown margin requirements.
Also as an interim measure for verifying shutdown margin in Modes 3. 4.
and 5, the licensee found that it was acceptable to borate to 2000 ppm to meet shutdown margin requirements with an immovable rod.
The inspectors concluded that the licensee had taken adequate corrective action by revising the shutdown margin procedure.
In addition, the licensee is also reviewing other surveillance procedures involving reactor engineering input.
This failure to update the shutdown margin verification procedure STP-134.001 to ensure adequate shutdown margin with an immovable rod is identified as a VIO.
This non-repetitive, licensee identified and corrected VIO is being treated as a Non-cited Violation (NCV) consistent with Section VII.B.1 of the NRC Enforcement Policy.
This is identified as NCV 50-395/97011-03.
c.
Conclusions An NCV was identified for an inadequate shutdown margin procedure to determine shutdown margin for a stuck rod.
The inspectors concluded that the licensee had taken adequate corrective action.
M8-Miscellaneous Maintenance 1ssues (92902)
M8.1 (Closed) VIO 50-395/96009-03:
failure to correctly aerform a weekly battery surveillance.
This issue involved a weekly 3attery surveillance that was performed with the battery on an equalize charge verses on float charge as required by TS 4.8.2.1.a.
ihe cause of the error was an inadequate surveillance procedure in that the procedure did not specify
_
all the necessary initial conditions.
The inspectors reviewed the
'
licensee's response to the VIO dated October 16, 1996; STP-501.001.
" Battery Weekly Test." Revision 9. dated February 4, 1997: and
.
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l
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l l
LER 50 395/M-08.
Appropriate initial conditions were incorpuated into the rt acedure to prevent recurrence of the issue.
M8.2 (Closed) LER 50-395/96 08:
missed surveillance on station battery.
This 1ssue was the subject if VIO 50-395/96009 03 which was discussed I
and closed in section h8.1 of this report.
Corrective actions for the l
violation discussed in Section M8.1 also apply to this LER.
M8.3 (Closed) LER 50-395/96 03:
entry into TS 4.0.3 due to missed l
surveillance.
Ih1s LLR addressed a licensee identified discrepancy in test methodologies required by TS 4.7.6.c.2 and the testing { performed.
The discrepancy resulted in the 15 surveillance requiremen not being j
met and an entry into 1S 4.0.3.
TS 4.0.3 allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to l
successfully complete a surveillance test following discovery of an j
inadequate test methoi In this case an emergency TS change was processed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> because the test metho2 used was different than that reluired by the TS but technically adequate.
The safety and regulatory significence of utilizing a test different than specified by theTSsisbO395/9600203:resently under NRC review and is being tracked by Unresolved item (URI)
Charcoal Absorber Tested in a Manner l
Different than Specif1ed in TS.
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III.
Enaineerina El Conduct of Engineering El.1 Reactor Makeun Water %vstem (RMWS) Guard Pine a.
Inspection Scone (37551),
On July 25. the insaectors observed a guard piae installed incorrectly on a RMWS line in t7e XMCIDA2v safety related iotor Control Center (MCC)
room.
b.
Observations and Findinas During a routine tour of the Auxiliary Building, the inspectors observed a six-inch diameter guard pipe, approximately seven feet long, which appeared to be incorrectly installed around a three-inch diameter RMWS line.
The guard pipe had shifted approximately two feet from its
.
intended position and was being supported by only one of the two installed sets of support lugs welded to the RMWS line.
The portion of RMWS piping and the guard pipe were located in the safety-related XMCIDA2Y 480 volt MCC room.
The inspectors reviewed FSAR Section 3.6.2.5.1 which describes the location and orientation of postulated design basis pipe breaks.
This section of the FSAR states in part:
" Cracks are postulated in moderate energy system piping in the vicinity of essential components.
l
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e
l Components located in the vicinity of moderate energy system piping were relocated. if practical, or were specified as spray proof.
In instances waere neither relocation nor specification as s possible, shields are provided." pray proof 1s Plant drawings referred to the aipe shield as a guard pipe and included details of the installation.
lle details shown on plam drawings E 304-794 and E-304-795 indicated that the soo9 ort lugs were co be we ded to l
the six-inch guard pipe to prevent movement of the quard telative to the l
RMWS line.
The licensee determined that this.vork had not been completed during plant construction which allowed the guard pipe to l
shift over time.
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1he inspectors informed the licensee of this condition and CER 97-0677 l
was generated to document the condition.
Non conformance Notice (NCN)
I 970677 was also written to determine the cause and corrective actions to
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be taken.
The NCN disposition specified that the guard pipe _ was to be welded to the support lugs.
The inspectors concluded that these actions were appropriate.
In addition, the licensee performed an engineering analysis to calculate the stress in the reactor make-up water line.
'
This evaluation concluded that the stress in this pipe satisfied the criteria for exemption from pipe crack Jostulation as discussed in Generic Letter 87 11. ' Relaxation in Ar)1trary Intermediate Pipe Rupture Requirements." The inspectors reviewed the evaluation and concluded that the conclusions of the evaluation were reasonable.
The inspectors were concerned that the as-built configuration in the plant did not match the drawings and that this condition had existed since construction.
,
l The licensee reviewed plant drawings and identified a total of seven similar guarc pipes (including the one identified by the inspectors).
The licensee conducted a field walkdown to ensure the as built configuration of the remaining six guard pipes matched the applicable drawings.
1here were no additional discrepancies identified.
Appendix B to 10 CFR Part 50. Criteria V. "Instractions. Procedures. and Drawings." states. " Activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructiors
)rocedures. or drawings."
In this case, the as found condition of t le guard pipe was not in accordance with the drawings.
This is identified as VIO 50-395/97011-04.
During the FSAR review, the inspectors noted that FSAR Secticn 3.6.2.4 i
" Guard Pipe Assembly Design Criteria." states that " Guard pipe assemblies are not used." However, the applicable drawings use this terminology to describe the assemblies referred to above.
The inspectors notified the licensee of this word conflict between t'ne FSAR t
and the plant drawings.
m
A V10 was identified concerning the failure to install a RMWS line guard pipe as shown on the applicable plant drawings.
The guard pipe acted as a spray shield to protect essential com)onents in the vicinity of the make up water line.
A discrepancy in 11e terminology used between the FSAR and the plant drawings was identified.
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E2 Engineering Support of Facilities and Equipment E2.1 Leadina Fdae Flow Meter (LEFM)
a.
Inspection Stone (37551)
l l
The inspectors reviewed the licensee's installation of the LEFM.
b.
Observations and Findinas l
l During the inspection period the licensee began using a LEFM installed on the main feedwater (FW) system header for determining exact FW flow t
l rates.
The LEFM is an ultrasonic flow measurir.g device.
The licensee I
determined that FW flow rates as measured by the FW venturis were low.
l The values determined by the LEFM will be compared with the flow rates (
from the plant's feedwater flow venturis to develo) normalization constants.
The LEFM will also be used to measure W temperature as an input to FW tem)erature normalization constants.
The normalization
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constants will ]e used to adjust the values from the FW flow venturis and FW RTDs which will still provide direct input into the thermal heat balance presently used by the plant,
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When the licensee input the LEFM generated normalization constants into the thermal heat balance indicated power dropped approximately one percent.
The licensee raised power about one percent to return reactor l
power to 100 percent ina1cated )ower.
The licensee realized an increase l
of approximately 30 megawatts tiermal.
'
The inspectors reviewed the licensee's safety evaluation and procedural controls established in Engineering Services Procedure, ES-560.120.
"Feedwater Flow Rate and Temperature Normalization Surveillance."
Revision 1.
The inspectors concluded that the license? had established adequate controls to prevent the plant operating above the licensed thermal limit.
c.
Conclusions The licensee established adequate controls for use of the LEFM to prevent the plant operating above the licensed thermal limi '
.
E7 Quality Assure:e in Engineering Activities E7.1 Review of Undated final Safety Analysis ReDort (UFSAR) Commitments (3/651)
A recent discovery of a licensee o>erating their facility in a manner contrary to the UFSAR description lighlighted the need for a special focused review that compared plant practices procedures and/or parameters to the UFSAR description.
While performing the inspections discussed in this report. the inspectors reviewed the applicable portions of the CSAR that related to the areas inspected.
An FSAR discrepancy was identified and is discussed in Section El.1.
E7.2 Safety System functional Inspections (SSFI)
a.
Insoection " cone (37550)
The licensee completed 11 SSFis from May 1987 through October 1996.
The
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I purpose of the SSFis was to assess the operational readiness of a system
'
(i.e., determine if the system was capable of performing its design j
basis function) and to resolve any deficiencies.
The inspectors reviewed the SSFis for the Emergency Feedwater System (completed May 1987) and the Residual Heat Removal System (completed April 1990).
,
b.
Observations and Findinns All the SSFis were managed and performed by the Independent Safety Engineering Group (ISEG).
This group was referenced in TS 6.2.3,
' Administration.' Each SSFI was conducted over approximately a one year l
3eriod.
SSFis were performed according to NSAC 121. * Guidelines for Jerforming Safety System Functional Inspections.' The licensee contracted for the services of outside consultants as deemed necessary to complete an SSFl. An SSF1 was a vertical slice review that included design basis, design changes, operations. testing and maintenance.
The inspectors observed that individual findings were categorized in terms of safety significance.
Corrective actions emanating from the SSFis had been tracked to completion by ISEG.
The Emergency Feedwater System SSFI had identified about 40 findings, and the NRC inspectors reviewed each of these for significance and to determine the ap]ropriate level of followup.
The most significant finding was on t le design of the instrument air for the air operated FW flow control valve.
The licensee's SSFl had identified that the
dedicated accumulator tank had been maintained at too low a pressure to meet the post-accident design requirement of maintaining the valve closed for three hours.
Corrective actions included replacing and relocating the regulator and relief valves with safety grade equipment.
The ins)ectors confirmed this modification through review of drawings.
Also, t1e regulator had been placed in the calibration program, which was confirmed by the inspectors.
The inspectors observed that the finding had been reviewed for generic implications.
Resolution of the finding had addressed the design of instrument air for the control room
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outside air intake valves. XVB 3B and XVB 4B.
The inspectors confirmed through drawing review that the design of instrument air for those valves did not have a similar problem.
i The RHR SSF1 had identified 15 comments for resolution on the system.
All of the comments were briefly reviewed and three that were ider,tified as having potential safety significance were selected by the inspectors l
for an in-depth review.
Those selected were as follows:
item No. RHR 1 - This item identified the fact that e
inconsistencies existed between the Safety injection System Design Basis Document (DBD) and the STPs.
The valve stroke times were based in the DBD solely on valve size and in the surveillance procedures on the design requirements of the system.
The (
requirement information was obtained from the system designer.
l Westinghouse, and the documents were made compatible.
I Item No. RHR 6 - This item addressed the potential loss of power
on either train of Safety injection for hot leg switchover in l
which some operations would have to be performed outside the control room.
The review revealed that the Emergency Operating Procedures (EOP) did not give special instructions to deal with the loss of Jower on either train.
Procedure E0P-2.2. " Transfer j
to Cold Leg Recirculation." Revision 9. now references Electrical Maintenance Procedure 100.006. " Emergency Installation of Cables for Si Valves." which gives the appropriate level of instructions.
This procedure also references that a repair kit be available in Warehouse B.
The inspectors verified thit the repair kit was appropriately placed and had the designated tool and materials.
item No. RHR 7 - This item raised a concern that a portion of the e
HVAC that is connected to a quality related vent path for the RWST
'
was not constructed to nuclear safety grade requirements.
An engineering calculation / evaluation showed that this six foot length of HVAC was acceptable and would not cause the RWST tank to fail, c.
Conclusions From the 11 SSFis completed by the licensee, inspectors reviewed the EFW and RHR SSFis which were completed in 1987 and 1990 respectively.
The inspectors concluded that these two SSFis were detailed inspections of broad scope performed by competent individuals.
The inspectors concluded that SSF1 findings had been resolved in a timely manner and generic implications were addressed.
E8 Hiscellaneous Engineering Issues (92903)
E8.1 (Onen) IFI 50-395/96009-04: inconsistent TS and design basis limits for service wa+er pond temperature.
The licensee identified that the 95 degree F SW temperature limit listed in TS 3.7.5. " Ultimate Heat Sink."
.
l doec not take in to ac e nt the temperature rise from a Loss of Coolant AcL1 dent (LOCA) and instrument uncertainties.
l 1he licensee revised the initial calculations based upon new information l
identified on the most limiting weather conditions and concluded that
!
the maximum SW pond temperature 'ise could be assumed to be l
approximately four degrees F instead of the 1.7 degrees originally l
calculated.
The SW intake temperature limit should therefore be 91 l
degrees F.
As corrective action the licensee is now limiting SW intake l
temperature to 85 degrees as read on the main control board instruments.
'
The licensee is also planning a thermal study of the SW pond.
Data is to be gathered during the shutdown for the refueling autage in October.
l 1he licensee has stated that a TS amendment will be submitted after a I
review of the pond thermal study results.
The licensee's "eview of past l
SW temperatures did not identify temperatures that exceeded the limit.
The licensee has also implemented a TS setpoint review woject.
The project will review all TS setpoint values and verify tlat measurement i
l accuracy is appropriately considered for surveillance criteria.
This
!
issue will remain open pending further NRC review of the resolution of this issue.
E8.2 (Closed) IFl 50-395/95013-03: charging /high head safety injection crossconnect valve lockout.
The purpose of this IFl was to monitor the
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licensee's corrective action for the' problem that the charging /high head safety injection cross connect valves. XVG-8133A and XVG 8133B, did not meet the single failure criterion.
These valves were in series and crossconnected redundant trains A and B.
When the swing high head safety injection pump was aligned to train B. spurious or inadvertent closure of either cross connect valve would result in termination of all high head safety injection. Administrative controls were in place since 1995 to offset this single failure vulnerability.
The licensee developed a system modification to meet the single failure criterion and eliminate the need for administrative controls. The system modification documentation, contained in ECR No. 50004. Revision 0, was reviewed by the inspectors.
It consisted of installing a second contactor in series with the existing starters for each of the two valves involved.
That second contactor would be controlled by a key switch at the main control panel.
This arrangement was called a power lockout feature and was i
i already utilized for other ecuipment for the same reason.
The power lockout feature would precluce spurious or inadvertent closure of a valve due to a postulated single failure.
The inspectors confirmed that the system modification was in the schedule for the October 1997 refuel outage by reference to the schedule itself and discussion with the Outage Manager.
E8.3 (Closed) VIO 50-395/96011-04: inadequate corrective action for design control error.
lhis item addressed the failure of the licensee to take corrective actions to creclude the recurrence of a design control error, i.e.. root cause was not addressed.
An underrated ASCO solenoid valve was installed and resulted in an inoperable Train A Charging Pump.
The inspectors reviewed the original NCN 5344. reviewed the revised procedure which should preclude recurrence of the problem, and noted
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.
that appropriate training had been conducted.
No new design / modifications have been issued since the revised design procedure was put in effect: however, the corrective actions are appropriate.
E8.4 IClosed) URI 50-395/96011-08: evaluation of motor operated valves for meeting requirements of Appendix R Section Ill.L.7.
The licensee performed a reanalysis, during 1996 to address the concerns expressed in NRC Information Notice 92-18. " Potential for loss of Remote Shutdown Capability durir,g a Control Room Fire." Specifically, the reanalysis consisted of evaluating the effects of postulated fire induced short-circuits in valve control wiring.
Since four valves were initially identified as potential problems, the URI was established.
Subsecuently, the licensee's evaluation of NRC Information Notice 92-18 inclucing the four valves was completed.
The analysis of the four valves mentioned in the URI was reviewed during this inspection, and is summarized as follows:
Valve XVG 8885, alternate high head safety injection cold leg
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recirculation isolation valve, was a normally closed valve that could be controlled from the control room but did not receive any automatic open/close signal.
This valve could spuriously open as a result of postulated fire damage to the control wiring.
The consequences of the valve spuriously openit.1 during a remote shut down to hot standby scenario would be to overfill the pressurizer.
Procedure FEP 4.0. " Control Room Evacuation Due to Fire." was revised to add to the list of valves that must be position verified as part of the post fire shut down procedure.
The inspectors verified through walkdown observation that the valve was accessible in an area with emergency lighting, and had a de-clutching lever, which would allow an operator to manually re-l close the valve should it have spuriously opened.
The inspectors also requested that the licensee determine whether maximum torque l
or thrust corresponding to the aostulated spurious opening could damage the valve to the point w1ere it could not then be manually
'
operated. The licenwc answered this question via Technical Work Record No. 13157, dated July 30. 1997.
The conclusion of this stress analysis was that the valve could still be manually operated.
LER 96-09. Outside Design Basis for Appendix R Analysis, documented the problem identified with valve XVG 8885 and the corrective actions.
LER 96-09 is also closed.
Valves XVG 888/A and 88878. low head recirculation train i
isolation, were normally open valves that could be controlled from the control room but did not receive any automatic open/close signal.
The inspectors confirmed that these valves, while part of the safe shutdown analysis for certain scenarios, were not aart of the safe shutdown analysis for fire in the control room.
T1e FEP procedure checks valve XVG 8887B to be closed, but this was a conservative step since closure would only backup valve XVG 8889 which is already locked closed.
Therefore these valves were not subject to the concern of NRC Information Notice 92-1 \\
.
Valve XVG 88098, refuel water storage tank residual heat removal
pump B suction valve, was a normally open valve.
The normal (open) position was the injection mode position.
The valve would be closed from the control room when transferring to cooldown
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mode.
The valve could spuriously close as a result of fire damage to the control wiring.
This was of no consequence to the safe shutdown analysis.
The open valve could receive a spurious o)en signal which could result in motor damage but, as determined )y weak link analysis. the valve could still be manually closed when
,
necessary to transfer to cooldown mode.
l IV.
Plant Sucoort l
R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 General Comments (71750)
l The inspectors observed radiological controls during the conduct of tours and found them to be acceptable.
R8 Hiscellaneous RP&C Issues (92904)
R8.1 (Closed) V10 50-395/96002-01: failure to follow procedure.
The V10 included three examples of instances in which licensee personnel failed to follow procedures.
The examples included a failure to properly monitor hand held computer logging equipment prior to releasing it from the radiologically controlled area, a failure to properly implement a SlP for testing of the B safety related battery, and a failure to follow the temporary shielding procedure during installation of lead shielding on RHR system and safety injection system piping.
The inspectors reviewed the licensee's response to the V10 dated May 8. 1996, corrective actions for each example, including improvements to 3rocedures HPP-158. " Contamination Control for Areas. Equipment and laterials." Revision 9. dated July 1, 1997. and STP-501.001
" Battery Weekly Test," Revision 9. dated February 4. 1997.
In addition, lice.:see management recognized the increased rate of human errors and initiated l
action to reinforce human error reduction techniques with licensee l
personnel.
S1 Conduct of Security and Safeguards Activities
$1.1 General Comments (71750)
The inspectors observed security activities including compensatory measures during the conduct of plant tours and plant activities and l
found them to be acceptable.
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V.
Manaaement Meetinas X1 Exit Meeting Summary The inspectors ) resented the inspection results to members of licensee management at t1e conclusion of the inspection on September 10, 1997.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED Licensee F. Bacon. Manager. Chemistry Services L. Blue. Manager. Health Physics S. Byrne. General Manager. Nuclear Plant Operations R. Clary. Manager. Quality Systems M. Fowlkes Manager. Operations S. Furstenberg. Manager. Maintenance Services D. Lavigne. General Manager. Nuclear Support Services G. Moffatt. Manager. Design Engineering K. Nettles. General Manager. Strategic Planning and Development H. O'Quinn. Manager. Nuclear Protection Services A. Rice. Manager. Nuclear Licensing and Operating Experience G. Taylor. Vice President. Nuclear Operations R. Waselus. Manager. Systems and Component Engineering R. White. Nuclear Coordinator. South Carolina Public Service Authority B. Williams. General Manager. Engineering Services G. Williams, Associate Manager. Operations
INSPECTION PROCEDURES USED
IP 37550: Engineering IP 37551: Onsite Engineering IP 61726: Surveillance Observations IP 62707: Maintenance Cuservations IP 71707: Plant Operations IP 71750: Plant Support Activities IP 92901: Followup - Plant Operations l
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IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering i
IP 92904: Followup Plant Support
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ITEMS OPENED. CLOSED AND DISCUSSED Opened 50-395/97011-01 IFl determina cause and corrective actions of degraded snubber conditions (Section M2.2).
l 50-395/97011-02 VIO failure to maintain the delta T-TAVG Protection Loop
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l Calibration procedures (Section M3.1).
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l 50 395/97011-03 NCV inadequate shutdown margin procedure to determine
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shutdown margin for a stuck rod (Section M3.2).
l 50 395/97011-04 VIO failure to install a reactor make-up line guard pipe l
in accordance with applicable drawings (Secticn
El.1).
l O_01td 50-395/96001-01 IFl partially submerged tendon inspection (Section 08.1).
50-395/96-02 LER voluntary entry into Technical Specification 3.0.3 l
(Section 08.2).
50-395/97011-03 NCV inadequate shutdown margin procedure to determine shutdown margin for a stuck rod (Section M3.2).
50 395/96009-03 VIO failure to correctly perform a weekly battery surveillance (Section M8.1).
I 50-395/96-08 LER missed surveillance on station battery (Section M8.2).
50-395/96-03 LER entry into Technical Specification 4.0.3 due to missed surveillance (Section M8.3).
l 50-395/95013-03 IFI charging /high head safety injection crossconnect valve lockout (Section E8.2).
50-395/96011-04 VIO inadequate corrective action for design control error (Section E8.3).
50-395/96011-08 URI evaluation of motor operated valves for meeting requirements of Appendix R Section Ill L.7 (Section E8.4)
50-395/96-09 LER outside design basis for Appendix R analysis (Section E8.4).
50-395/96002-01 V10 failure to follow procedure (Section R8.1).
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/
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o P_iscussed 50 395/96009-04 IFI inconsistent Technical Specification and Design Basis
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Limits for service water pond temperature (Section E8.1).
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N
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' t,
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e e
contamination levels exceeded the action limit and clean ups were not
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done or were late. Some of the AUs were repeatedly failing to perform surveys as required. On July 25, 1997, while touring the research labs, the inspectors observed a container marked radioactive materials
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adjacent to a piece of equipment in one of the labs. A researcher in the lab had just advised them that material was not in use in that particular lab.
In fact, material was present in the lab, but came from another researcher who needed access to a particular piece of equipment.
The inspectors advised the RSO that there was a potential, in this type of use, for a lab not to be surveyed as required, since neither the researcher whose lab contains the equipment nor the visiting researcher are required to perform a weekly survey, in this event, c. Conc Wsions Weekly and monthly surveys are not performed as required by the RSM.
This is a violation which is discussed in Section 01 above. Leak tests and inventories of sealed sources were performed as required by License E
Condition 15.
07.
Personnel Radiation Protection (87100)
a. Espm The inspectors reviewed radiation exposure records from July 1996 to June 1997 and discussed those records with cognizant licensee personnel to determine if the licensee was meeting limits specified in 10 CFR 20 and their ALARA committment, b. Observations and Findinas Licensee personnel were issued whole body and extremity dosimetry as required, and the dosimetr-y was exchanged on a monthly basis. Thyr _oid_ _
monitoring was performed as needed.
The highest total effective dose equivalent (TEDE) for the period reviewed was 270 mrem in 1996 and 230 mrem in 1997. During the inspection, the inspectors observed licensee personnel wearing radiation dosimetry appropriately to detect radiation
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exposure during the handling and use of radioactive material at the facility.
c. Conclusions The inspectors determined that the licensee was maintaining personnel radiation exposures As low As Reasonably Achievable and that no NRC regulatory radiation exposure limit had been exceede :, n.w.
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08.
Radioactive Wtste Manaaement (87100)
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a. k opf
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I The inspectors reviewed procedures and records and interviewed cognizant l'censee personnel to determine if radioactive waste was managed in accordance with regulatory and license requirements.
b. Observations and Findinas The licensee is authorized to dispose of radioactive waste in several ways.
Radioactive material with a half life of less than sixty five days is held for decay in storage before dis >osal as ordinary waste, after surveys prove that the waste is at or yelow background. Waste from nuclear medicine is disposed as bichazardous waste after decay, or is transferred to the waste storage area.
Unused radiopharmaceuticals are returned to the supplier.
Radioactive liquids may >e disposed of by release to the sewer in accordance with Appendix R to Regulatory Guide E
10.8. Revision 2.
Liquid scintillation counting vials are disposed of by transfer to a commercial incinerator.
Other waste and animal carcasses are transferred to a commercial radioactive waste burial site.
On March 28, 1997, the licensee discovered that four spent Tc 99m syringes had been disposed of prior to decay.
This was an isolated event, as the amount was below that requiring NRC notification. The responsible individual was counseled, the shielded sharps containers were relabeled with ' Caution Radioactive Material" labels. and a label affixed advising that only Nuclear Medicine personnel could empty these containers. The licensee has a mechanical compactor in the waste storage facility, and sNe waste is compacted prior to disposal to a waste site, c. Conclusions
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The licensee maintains its waste management program in accordance with license commitments and regulatory requirements.
09.
Transoortation a 29PA The inspectors reviewed the licensee's transportation practices to ensure that they were conducted in accordance with regulatory requirements.
b. Observations and Findinos Shipping papert reviewed were accurate and complete. Radio-pharmaceuticals are delivered and retrieved, if necessary by a commercial nuclear pharmacy. Waste is picked and sent to a burial site by a contract carrier.
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