IR 05000280/1998005
| ML20236Q681 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 07/13/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20236Q677 | List: |
| References | |
| 50-280-98-05, 50-280-98-5, 50-281-98-05, 50-281-98-5, NUDOCS 9807200406 | |
| Download: ML20236Q681 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket No . 50-281 License No DPR-32. DPR-37 Report No: 50-280/98-05, 50-281/98-05
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Licensee: Virginia Electric and Power Company (VEPCO)
Facility: Surry Power Station. Units 1 & 2 Location: 5850 Hog Island Road Surry. VA 23883
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Dates: May 3 - June 13, 1998 Inspectors: R. Musser. Senior Resident Inspector K. Poertner. Resident Inspector E. Girard. Reactor Inspector (Sections E8.1. E E8.3. and E8.4)
P. Hopkins Project Engineer (Sections 01.1. 02.1 and El.1)
Approved by: R. Haag Chief. Reactor Projects Branch 5 l Division of Reactor Projects 1 l
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ENCLOSURE 9807200406 980713 PDR ADOCK 05000280 G PDR
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i EXECUTIVE SUMMARY Surry' Power Station. Units 1 & 2 NRC Inspection Report Nos. 50-280/98.05. 50-281/98-05 This integrated inspection included aspects of licensee operations, engineer-ing, maintenance. and plant support. The report covers a six-week period of resident inspection: in-addition. it includes the results of inspections by regional project and reactor inspector Doerations
- The licensee's. sensitivity to a minor increase (a) proximate 0.20 gpm) in reactor coolant system leakage was noteworthy. T1e source of increased leakage was promptly identified as a non-isolable leak in the C reactor coolant pump seal.1njection line. Technical S) edification requirements
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- were complied with by placing Unit = 1 in cold slutdown (Section 01.2). [
- Operations demonstrated a good questioning attitude by identifying that
_ normally closed containment isolation sample valves were leaking into a sample sink. Declaring the containment isolation valves inoperable, securing the leak path from containment by closing manual valves and calculating the contribution to the total containment leakage adequately addressed the leakage through both containment isolation valves (Section
01.3).
. The Unit 1 startup was performed in a well controlled manner and in
- accordance with operating procedure The operating crew was well focused on tasks throughout the evolution (Section 01.4).
- An unresolved item was identified concerning non-conservative power calculations resulting from out of calibration feedwater resistance temperature detectors (Section.01.5).
- Although.not required by regulations, the licensee performs monthly sampling of containment air to determine the hydrogen concentratio The sampling resulted in the identification and correction of a steam leak which had increased the Unit 2 containment hydrogen concentration from non-detectable to 0.72 percent. The containment air sampling program for: hydrogen is considered a strength (Section 01.6).
. Control room logs reflected accurate and updated plant status information. Nine control room drawings had illegible drawing identification numbers. These items were promptly corrected (Section 02.1).
Maintenance e Unit 2 turbine governor valve maintenance was well coordinated between operations and maintenance. The valve was repaired and returned to service expeditiously following initiation of the work activity (Section M1.1).
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. Unit 1 safety injection logic testing was accomplished in accordance l with the procedure requirements and the test results were acceptable (Section M1.2).
. Reactor coolant system valve 1-RC-6 was replaced in accordance with approved procedures. A negative finding was identified in that, following removal and prior to installing the new valve, continuous ;
monitoring of the freeze seal was not provided by maintenance Jersonne This did not meet station management's expectations which had Jeen conveyed to maintenance prior to the freeze seal installation (Section M1.3).
Enaineerina
. Modification procedures and guidelines provided an effective process for modification implementation (Section E1.1).
e The modification process required that drawings be placed in the control l room, the document control system, the Technical Support Center, and the
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Simulator Control Room before modified systems were placed in operatio The drawing change process included a second verification to ensure ;
drawings were updated prior to a modified system being declared operable (Section E1.1). {
. The safety evaluation assessments of two modifications were thoroug I The use of mock ups for training of personnel on modification installation and system operation was an excellent practice (Section E1.1). )
Plant Succort
. Health physics practices were observed to be proper (Section R1).
. Security and material condition of the protected area perimeter barrier 1 were acceptable (Section S1). l l
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Reoort Details Summarv of Plant Status Unit 1 operated at power until May 10, 1998, when the unit was removed from service to repair a non-isolable seal injection line leak. The unit was returned to service on May 25. 199 Unit 2 operated at power the entire reporting perio I. Operations
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01 Conduct of Operations
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01.1 General Comments (71707. 40500)
The inspectors conducted frequent control room tours to verify proper staffing, operator attentiveness, and adherence to approved procedure 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 housekeepin Deviation Reports (DRs) were reviewed to assure that potential safety '
concerns were properly reported and resolved. The inspectors found that daily operations were generally conducted in accordance with regulatory requirements and plant procedures.
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During control room visits. the inspectors observed operators perform control board walkdowns with relief operators. The inspectors observed shift relief turnovers. Oncoming operations personnel were well briefed on present plant status and control board indications for the past 24 l hour With Unit 1 shutdown, additional licensed operators were assigned to the l control room. Staffing was adequate, personnel were attentive to plant conditions and procedures were used during control room activities.
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01.2 Unit 1 C Reactor Coolant Pumo (RCP) Seal In.iection Line Non-Isolable i Leak and Subseauent Forced Outaae Insoection Scooe (71707)
The inspectors performed a review of the licensee's initial and follow-up actions related to non-isolable leaks on the C RCP seal injection line and Reactor Coolant System (RCS) valve 1-RC-6.
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2 Observations and Findinas On May 9. while operating at 100 percent power. the licensee detected a slight increase in RCS unidentified leakage. The leak rate had changed from a previous value of approximately 0.2 gallons per minute (gpm) to 0.4 gpm. A containment entry was performed and a leak was detected in
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the vicinity of the C RCP seal injection line. Due to high radiation conditions in the area, stay time was limited and a second entry at reduced power (50 percent) was required to positively identify that the leak was on the seal injection line and was non-isolable. Additionally, some vibration of the seal injection line was observed. At 11:04 p. a shutdown of Unit '1 was. initiated as required by TS 3.1.C.4. An unusual event was declared in accordance with the licensee's emergency l plan for a RCS leak requiring a plant shutdown per the plant's T A
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report was made to the NRC operations center in accordance with 10 CFR 50.72. The unit reached cold shutdown on May 10..at 9:54 ).m.. and the unusual event was terminated. Since the change in RCS leacage was well within the allowable TS unidentified leakrate limit of less than gpm the licensee demonstrated a conservative approach to RCS leakage by investigating the source of the leakage and identifying the non-isolable .
lea I Following shutdown of the unit, an inspection of the subject area revealed a 1-inch crack at the toe of the fillet weld where the seal injection line connects to the thermal barrier flange. When looking at the RCP. the crack spanned from the 12 o' clock position to the two .
o' clock position. To ensure a similar condition did not exist on either the A or B RCP seal injection lines, a liquid penetrant inspection was performed on these lines and no exterior flaws were identifie Additionally, a walkdown of the piping hangers / supports for the three RCPs was performe The hanger configuration for the A and B RCP seal injection lines was found to be satisfactor However, a vertical hanger on the C RCP seal injection line was found to be loose and not fully sup)orting the piping. Based on the condition of the vertical hanger, t1e vibration, observed during the initial identification of the leak, was postulated to have resulted in propagation of a pre-existing flaw to failure. An actual metallurgical evaluation of the flaw area was not performed because the flaw was destroyed during the removal of the seal injection line. The licensee replaced a portion of the seal injection line, rewelded the line into place and properly reset the vertical hange Once the maintenance was completed, heatup and pressurization of the
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unit commenced. With Unit 1 at normal operating temperature and pressure, a leak was observed on RCS valve 1-RC-6 (loop A bypass
- instrumentation line isolation valve). The leakage was observed from
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the valve's packing gland. Following a partially unsuccessful leak repair of the packing gland leak, a through-wall leak was also observed
, at the bonnet of the valve. Station engineering determined that the
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leakage was non-isolable RCS pressure boundary leakage. At 4:24 p.m. on May 20. a cooldown of Unit 1 was initiated as required by TS 3.1. Another report was made to the NRC operations center in accordance with 1 \
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10 CFR 50.72. An unusual event was again declared in accordance with the licensee's emergency plan. The unit reached cold shutdown on May 21, at 7:13 a.m. and the unusual event was terminate Valve 1-RC-6 was replaced (Section M1.3). Following the completion of repairs Unit 1 was returned to servic l The licensee performed a metallurgical examination of valve 1-RC-6 and
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determined that the flaw / leakage observed was not from the valve bonnet.
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but through the threaded connection between the valve bonnet and body and out through a defect in a seal weld. Following this determination, the licensee retracted the second 10 CFR 50.72 notificatio Conclusions The licensee's sensitivity to a minor increase (a) proximate 0.20 gpm) in reactor coolant system leakage was noteworthy. T1e source of increased l leakage was promptly identified as a non-isolable leak in the C reactor l coolant pump seal injection line. Technical S) edification requirements were complied with by placing Unit 1 in cold slutdow .3 Unit 1 Containment Samole Penetration Leakaae l Insoection Scooe (71707)
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The inspectors reviewed the disposition of an RCS cold leg sample
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penetration that was leaking during a reactor startu Observations and Findinas i On May 25. during a restart of Unit 1 from a maintenance outage, an i operator, while on routine rounds, identified approximately 25 cubic l centimeters per second flow into the Unit 1 sample sink. Further
! investigation revealed that normally closed RCS cold leg sample containment isolation valves were leaking past their seats. The operating crew declared the containment isolation valves inoperable and
! closed the manual isolation valve downstream of the penetration to stop the leakage. Declaring the containment isolation valves inoperable and
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securing the leak path from containment reflected a conservative l approach to operations. Also. Operations demonstrated a good questioning attitude by identifying the unexpected leakage into the sample sink l Engineering performed a type C leakage estimate for the penetration
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based on the identified' leakage and calculated a leakrate of 57 standard cubic feet per hour which when added to the total containment leakage was still below the maximum allowed total containment leakage. The leakrate estimate was performed with both containment isolation valves shu Prior to the unit restart the licensee deactivated the outside containment isolation valve. Subsequent to the unit restart the licensee deactivated and tagged the inside containment isolation valve closed. The licensee plans to operate with the penetration isolated for
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the remainder of the operating cycle.
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4 Conclusions Operations demonstrated a good questioning attitude by identifying that normally closed containment isolation sample valves were leaking into a sample sink. Declaring the containment isolation valves inoperable, securing.the leak path from containment by closing manual valves and calculating the contribution to the total containment leakage adequately addressed the leakage through both containment isolation valve .4 Unit 1 Reactor Startuo Insoection Scone (71707)
The inspectors observed portions of a Unit 1 reactor startup from a forced outag Observations and Findinos On May 25. the inspectors. observed the startup of the Unit 1 reacto Rod withdrawal commenced at 10:49 a.m.. with the reactor attaining criticality at 12:06 ).m. The inspectors observed that the operating crew was focused on t1e startup activities. All evolutions were performed in a controlled manner and in accordance with applicable operating procedure Conclusion The Unit 1 startup was performed in a well controlled manner and in accordance with operating procedures. The operating crew was well focused on tasks throughout the evolutio .5 Unit 2 Feedwater Temperature Insoection Scooe (71707)
The inspectors reviewed the disposition of a Unit 2 feedwater temperature anomaly, Observations and Findinas On June 4. the licensee identified that Unit 2 feedwater temperatures were reading approximately 4 F higher than nominal 100 percent power values. This was identified during a review of secondary performance parameters. All three feedwater temperature detectors indicated 4
' approximately 445 F versus a nominal 100 percent value of approximately 441 Higher indicated feedwater temperatures would have a non-conservative effect on the reactor power determination. The licensee reduced indicated reactor power to 99 percent on June 5 to compensate i for the increased feedwater temperature indication. The licensee had '
changed the feedwater Resistance Temperature Detector (RTD) calibration methodology during the last calibration on May 28. The feedwater RTDs ,
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were recalibrates using the pre-May 28 methodology and the unit was returned to 100 percent indicated power on June Prior to the May calibration. vendor provided RTD temperature curves were used to calibrate the instrument loops. During the May calibration the RTDs were removed from their thermowells and placed in an oil bath to calibrate the instrument loop. A review of the original calibration procedure and the revised calibration procedure determined that the acceptance criteria stayed the same. Both procedures required that the RTDs be within plus or minus 3 F of the input temperature value. The licensee stated that the test methodology was revised to allow use of the actual RTD instead of a test instrument to provide the input calibration signal. The initial review by reactor engineering determined that the calorimetric program assumed a 9.5 F uncertainty in feedsater temperature and they concluded that, even with the higher feedwater temperatures, the indicated reactor power had remained within the uncertainty analysi The licensee initiated a DR and a category 3 root cause evaluation to determine why the two calibration methods resulted in different feedwater temperatures. Engineering initiated an engineering transmittal to address feedwater RTD uncertainty considerations. The licensee had not completed the root cause evaluation or engineering transmittal as of the end of the inspection period. Review of licensee actions to address the non-conservative feedwater temperature RTDs with respect to reactor power is identified as Unresolved Item (URI) 50-281/98005-01. Non-conservative reactor power calculation resulting from out of calibration feedwater RTD Conclusions An unresolved item was identified concerning non-conservative power calculations resulting from out of calibration feedwater temperature detector .6 Unit 2 Containment Hvdrocen Concentration Insoection ScoDe (71707)
The inspectors reviewed licensee actions with respect to increased hydrogen concentration inside the Unit 2 containmen Observations and Findinos On June 12. during routine monthly sampling of the Unit 2 containment atmosphere, the licensee detected increased concentrations of hydroge The sampling detected a hydrogen concentration of 0.72 percent. The previous monthly sample had no detectable hydrogen concentration. Based on the sample results the licensee obtained backup containment atmosphere samples that confirmed the increased hydrogen concentratio __-_ _ _ - _ _ - _ _ _ _ _ - _ _ - _ - - - _ __ _ _ _ - _ _ - - _ _ _ -
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The licensee conducted a containment entry to obtain local air samples and to inspect the pressurizer cubicle for indications of a steam lea The licensee also initiated increased RCS leakrate calculations and containment sampling and initiated a feed and bleed of the containment i air. Hydrogen. concentration stabilized at approximately-0.72 percen Local samples were consistent with the remote sample result Throughout the operating cycle RCS leakage had been consistently low RCS leakrate calculations performed after the increased hydrogen concentration was identified were consistent with previous calculated value Total RCS leakage values ranged between 0.1 gpm and 0.15 gp Initial containment entries failed to identify the source of the hydrogen. The licensee inspected the area outside the pressurizer steam space, sampled and inspected the primary relief tank and inspected the pressurizer Power Operated Relief Valves'(PORVst for packing leakag The licensee also initiated a temporary. modification to install a
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hydrogen recombiner inside containment to help reduce hydrogen concentratio Subsequent containment entries identified that the solenoid operated pressurizer vent valves were leaking by their seats. These valves are located'in the pressurizer cubicle but the discharge piping is routed to the reactor cavity area. The manual isolation valve for the pressurizer vent valves was shut.to isolate the leakage. Hydrogen concentration inside containment started to decrease following isolation of the-pressurizer vent valve 'The licensee has established an administrative limit on hydrogen
. concentration inside containment. The present maximum hydrogen concentration allowed is 0.75 percent. The administrative limit was
. established to ensure that post loss-of-coolant-accident containment hydrogen concentration would not exceed 4 percent. The licensee initiated routine monthly sampling of containment hydrogen concentration in the past to ensure that the units were operated within the design envelope assumed in the accident analysis. Based on the sudden increase in hydrogen concentration over a period of a month the licensee is reviewing the sample frequency. A strength was identified for performing routine containment atmosphere hydrogen sampling. This sampling is not required by regulations; however, it helps ensure that hydrogen concentrations remain within design assumption Conclusions Although not required by regulations, the licensee performs monthly i sampling of containment air to determine the hydrogen concentratio ;
The sampling resulted in the identification and correction of a steam i leak which had increased the Unit 2 containment hydrogen concentration I from non-detectable to 0.72 percent. The containment air sampling program for hydrogen is considered a strengt , '
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02 Operational Status of Facilities and Equipment 02.1 Review of Control Room Logs and Control Room Orawings Insoection Scone (71707)
The inspectors reviewed control room logs and drawings during control room visit Observations and Findinos The inspectors observed that control room logs reflected plant statu Operations personnel entered accurate plant data information into the appropriate logs. The inspectors, while reviewing control room drawings, identified nine examples of illegible drawing identification numbers. The shift supervisor took immediate action to replace these drawing ,
I Conclusions Control room logs reflected accurate and updated plant status information. Nine control room drawings had illegible drawing i identification numbers. These items were promptly correcte )
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II. Maintenance M1 Conduct of Maintenance M1.1 Unit 2 Main Turbine Governor Valve Maintenance J_nsoection Stone (62707)
The inspectors followed licensee actions to repair a failed turbine governor valv '1 observations end Findinas On June 7. durirg a tour of the high pressure turbine enclosure the licercee determined that the valve closure spring assembly associated ,
with ti:e #2 turbine governor valve had failed. The spring assembly '
became af sconnected from the valve due to a spring assembly holddown bolt failure. The #2 governor valve was fully open at the time of the failure and remained open following the failure. The valve spring assembly supplies the motive force to close the valve and Electro-Hydraulic Control (EHC) fluid provides the motive force to open the valv The licensee contacted the turbine valve vendor Westinghouse, and initiated a task team to generate a repair plan. The licensee decided to remain at )ower and repair the valve online. On May 10 the licensee immobilized tie #2 governor valve and isolated EHC fluid to the valv Following isolation of the valve the operations crew reduced reactor I
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power to approximately 73 percent. Maintenance personnel then jacked the #2 governor valve closed and replaced the spring assembly using WO 00390641. " Reinstall Springs on #2 Governor Valve." Following replacement of the spring assembly the valve was reopened using the test pushbuttons in the control room, and the unit was returned to full powe The inspectors reviewed the work package and monitored work activities in progress. The inspectors also monitored control room activities during the power reduction. The work activity was well coordinated between operations and maintenance and the valve was repaired and returned to service expeditiously following initiation of the work activity.
- Conclusions Unit 2 turbine governor valve maintenance was well coordinated between operations and maintenance. The valve was repaired and returned to service expeditiously following initiation of the work activit M1.2 Safety Iniection Loaic Test Inspection Scooe (61726)
The inspectors observed the performance of Unit 1 safety injection logic-testing, Observations and Findinas On May 11. the inspectors observed the performance of procedure 1-IPT-FT-RP-SI-0018. " Safety Injection Logic Testing Train B." The licensee performed the sections of the procedure associated with high steam flow coincidence with low Tave or low steam generator pressure. The testing was performed in accordance with the procedural requirements, and the test results were acceptabl Conclusions Unit 1 safety injection logic testing was accomplished in accordance with the procedure requirements and the test results were acceptable.
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M1.3 Replacement of RCS Valve 1-RC-6 Insoection ScoDe (62707)
The inspectors observed portions of the preparation and replacement of RCS valve 1-RC-6. the loop A bypass instrumentation line isolation valve.
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, Observations and Findinas On May 20. as discussed in Section 01.2. the licensee determined that RCS valve 1-RC-6 required replacement due to a through wall leak in the valve bonnet. To remove the valve from the RCS, a freeze seal was established on both sides of valve 1-RC-6. The licensee utilized freeze seals because working the valve without freeze seals would have required a complete core offload. The inspectors observed the licensee's preparation for the removal of valve 1-RC-6 and reviewed the freeze seal procedure. 0-MCM-1918-03 " Freeze Seal of Piping." revision 4 OTO The procedure was revised to provide more detail for the installation of the freeze seals on the piping adjacent to valve 1-RC-6. Additionally, a safety evaluation. 98-0060. was prepared to evaluate the adequacy of the controls to be implemented while performing the evolution. Included
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in these documents were contingency plans to be implemented in case of a freeze seal failure. These contingency plans included the installation of a clamp assembly that could be either placed over a partially cut pipe or installed over the pipe end once the valve was remove Additionally, wooden plugs were to be available for installation into the pipe opening if needed. Plant management's expectation was that the freeze seals were continuously monitored by maintenance personnel, so that in case of a freeze seal failure, the above described contingencies could be carried out. Monitoring of the freeze seals was expected until the new valve was welded into plac The inspectors observed the removal of valve 1-RC- Upon removing the valve no leakage was noted coming from the that the freeze seals were holding properly. piping The newsystem indicating valve was expeditiously installed, minimizing the time that the freeze seals were relied upon as isolation boundarie Following removal of valve 1-RC-6 and prior to the installation of the new valve, the inspectors noted that no maintenance personnel were monitoring the freeze seals to ensure that they were holding properl The inspectors informed the operations shift supervisor. In later discussions with licensee management, the inspectors were informed that the person assigned to monitor the piping had injured his finger and determined that he had to exit containment to potentially seek medical treatment. However, he did not require one of his colleagues to remain in the area to monitor the freeze seals. In leaving the area without assuring proper monitoring of the freeze seals, management's expectations of continuous monitoring were not met. Although another cognizant licensee person was at the job site within 15 minutes, this matter is considered a negative finding, in that, the expectations of station management were not fully me )
i Conclusions l
Reactor coolant system valve 1-RC-6 was replaced in accordance with approved procedures. A negative finding was identified, in tha '
following removal and prior to installing the new valve, continuous monitoring of the freeze seals was not provided by maintenance j
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Jersonne This did not meet station managements expectations which had
)een conveyed to maintenance prior to the freeze seal installation III. Engineering El Conduct of Engineering E1.1 Onsite Enaineerina Insoection Scope (37551)
The inspectors reviewed Design Change Packages (DCPs) and modification process procedures. The inspectors also interviewed engineering, maintenance, operations and training personnel to ascertain their F understanding of the modification process and their participation. The modifications selected for review included DCP 97-060. " Low Level Instrument Air (IA) Modification for Units 1 & 2" and DCP 94-18- " Electrical Power Low Voltage Vital Bus Panel Breaker Coordination." I Observations and Findinas The inspectors reviewed documents and interviewed a number of engineers who were involved in the DCP process. The inspectors also reviewed associated DCP work controls, documentation, and observed management involvement. Design control of DCPs was effectively coordinated with engineering, operations, maintenance and support groups. Design modifications were reviewed by appropriate Jersons representing engineering, maintenance and operations. T1e interfacing controls were clear in defining responsibilities, appropriate contact persons and proper risk assessment of the projec The inspectors' review verified that DCP 94-18-3 modified the Uninterruptible Power Supply (UPS) power to the vital bus distribution panels in the control room. The modification replaced the 100 Amp main circuit breakers in each vital bus distribution panel with non-automatic molded case switches. The modification satisfactorily resolved an Appendix R coordination issue which was discussed in NRC Inspection Reports Nos. 50-280. 281/97-09. The inspectors confirmed that the compensatory measures implemented per justification for continued operation C-97-003 were not needed after the modification. The associated safety evaluation adequately addressed issues associated with the installation and operation of the modification. A safety evaluation assessment ensured that the W0s and the installation procedures had been properly revised for the specific vital bus to be deenergized during the !
electrical work. For exam)le, jumpers were specified in work documents to prevent actuations on t1e opposite unit. The inspectors noted that engineering had worked closely with outage planning and operations to issue a field change which resulted from the safety evaluation assessmen Reviews of DCP 94-18-3 and DCP 97-060 and associated documentation were performed by the inspector The reviews revealed that seismic analyses
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were complete Equipment parts were properly added to the required parts lists and controlled documents and drawings, technical manuals, and operational and maintenance procedures were revised before system operation. Drawings were properly reviewed and placed in the control room in hard copies and placed in the document control system before the systems were placed into service. The drawing change process used a second verification to ensure that drawings were in place before the system was declared operable. Furthermore, the inspectors verified by revia of training modules, attendance records and observation of a requa ification training class that required operator and maintenance training had been completed. The inspectors verified that personnel were well trained and understood installation instructions and the precautionary measures to be taken. Operations and maintenance personnel were trained on the new procedures and equipment operation prior to placement of the systems into service. The use of mock-ups for training of personnel on the installation and operation of the systems was an excellent practice. Post modification testing was completed and achieved the intended results. The inspectors also observed during implementation of DCP 97-060 that engineering personnel performed reviews and observations during the modification installatio Conclusions Modification procedures and guidelines provided an effective process for implementing plant change The modification process required that drawings be placed in the control room, the document control system, the Technical Support Center, and the Simulator Control Room before the modified systems were placed in operation. The drawing change process included a second verification to ensure drawings were updated prior to a modified system being declared operabl The safety evaluation assessments of two modifications were thoroug The use of mock-ups for training of parsonnel on the installation and system operation was an excellent practic E8 Miscellaneous Engineering Issues (92903)
E (Closed) Insoection Followuo Item (IFI) 50-280. 281/96003-02: Increase margin for PORV block valves. This item was opened for followup of a licensee commitment to increase the closing capabilities of the PORV block valves. Motor-Operated Valves (MOVs) 1-RC-MOV-1535 and 1536 and 2-RC-MOV-2535. The closing margin above flow cutoff for these valves
, was to be raised 10 to 15%. This could be accomplished by bypassing the close torque switch for the valves In the current inspection, the inspectors verified documented completion of the commitment on Commitment Tracking System (CTS) Item No. 343 Further, the inspectors reviewed DCP 92-083.15. Revision 23. and verified that it specified the appropriate changes and diagnostic testing. In addition, the inspectors verified that completion of the
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work to implement the changes and the diagnostic testing had been documented in the followings W0s:
WO 340104 2-RC-MOV-2535 (reset TS bypass to 0%/ VOTES test)
WO 340257 1-RC-MOV-1535 (reset TS bypass to 0%/ VOTES test)
WO 340258 1-RC-MOV-1536 (reset TS bypass to 0%/ VOTES test)
E8.2 (Closed) IFI 50-280. 281/96003-03: Dynamic test to verify torque required for 96-inch Pratt butterfly valves. This item was opened for followup of a licensee commitment to dynamically diagnostic test a 96-inch Pratt butterfly valve to support the sizing methodology. In the current inspection. the inspectors verified documented completion of the commitment on CTS Item No. 343 The inspectors also reviewed a copy of the diagnostic test data (dated May 7, 1996) and a licensee memorandum
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(dated September 24. 1996)-which summarized and evaluated the results of the completed test. The evaluation found that the test demonstrated that the methodology used for sizing the valves had been conservativ E8.3 (Closed) IFI 50-280. 281/96003-04: Static diagnostic measurements on Posiseal butterfly valves. This item was opened for followup on the results of static diagnostic testing which the licensee ]lanned to Jerform on butterfly valves manufactured by Posiseal. T1e inspectors lad a concern that torque requirements determined for these valves using the manufacturer's methodology might.not be conservative. The diagnostic tests were expected to resolve this concer In the current inspection. the inspectors verified documented completion of the tests on CTS Item No. 3490. The following test data was reviewed:
Test 29 (10/21/97) on valve RS-256B Test 10 (4/9/97) on valve CS-101A Test 7 (4/4/97) on valve CS-101B Test 2 (4/1/97) on valve CS-101C ,
Test 9 (3/21/97) on valve CS-101D i l
The inspectors also reviewed a summary tabulation of test data from all testing of the Posiseal butterfly valves. The data showed that the maximum torque requirements predicted, based on the manufacturer's
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methodology. were adequate. However, the data also showed that the I unseating torques were higher than predicted for several valve '
Licensee personnel stated that they believed the high unseating torcues .
were due to setting the control switches to seat the valves too harc i into the seat in an attempt to assure leak tightness. The licensee had l initiated W0s to overhaul two of the valves (CS-101A and C on W0s 365785 and 375175) due to possible damage from the high seating torque and planned to lower the seating torque on a third (CS-101D on WO 389739).
The licensee indicated that in the future the butterfly valves would be set-up using strain gage torque measurements to assure against excessive L seating forces. The inspectors were shown purchase orders for the i strain gages to be used in this application.
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E8.4 (Closed) IFI 50-280. 281/96003-05: Revision of overthrust /overtorcue procedure. NRC Inspection Report Nos. 50-280. 281/96-03 identifiec that the licensee's procedural requirements for evaluating MOV actuator overthrust /overtorque occurrences was inconsistent with guidance
, provided by the actuator manufacturer in Limitorque Maintenance Update l 92- The licensee's requirements had been documented in Procedure SSES-3.03. " Controlling Procedure Providing Guidelines for Addressing MOV Design Issues." Revision In the current inspection. the inspectors reviewed the licensee's requirements for evaluating overthrust and overtorque events which were now incorporated in Procedure SSES-8.19. " Controlling Procedure Providing Guidelines for Addressing MOV Design Issues." Revision 1. The inspectors found the procedure adequately addressed the guidance provided by the actuator manufacturer in Limitorque Maintenance Update 92- IV. Plant Support R1 Radiological Protection and Chemistry Controls (71750)
On numerous occasions during the inspection period, the inspectors reviewed Radiation Protection (RP) practices including radiation control area entry and exit, survey results, and radiological area material conditions. No discrepancies were noted, and the inspectors determined that RP practices were prope S1 Conduct of Security and Safeguards Activities (71750)
On numerous occasions during the inspection period, the inspectors performed walkaowns of the protected area perimeter to assess security and general barrier conditions. No deficiencies were noted and the inspectors concluded that security posts were properly manned and that the perimeter barrier's material condition was properly maintaine V. Manaaement Meetinas X1 Exit Meeting Summary The inspectors 3 resented the inspection results to members of licensee management at t1e conclusion of the inspection on June 24. The licensee acknowledged the findings presente The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identi fie _ _ _ _ ____
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PARTIAL LIST OF PERSONS CONTACTED M. Adams, Superintendent, Engineering
. R. Allen, Superintendent. Maintenance
! R. Blount. Manager, Nuclear Safety & Licensing D.' Christian. Site Vice President M. Crist. Su)erintendent. Operations l- E. Collins )irector, Nuclear Oversight L B. Shriver. Manager. Operations & Maintenance l T. Sowers. Superintendent. Training L B. Stanley, Supervisor. Licensing W. Thorton. Superintendent, Radiological Protection INSPECTION PROCEDURES USED IP 37551: Onsite Engineering- . .
l IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems
.IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations
!- 'IP 71750: Plant Support Activities L IP 92903: Followup - Engineering l
l- ITEMS OPENED AND CLOSED l Ooened
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.50-281/98005-01 URI -Non-conservative reactor power calculation resulting from out of calibration feedwater RTDs (Section 01.5).
Closed 50-280 281/96003-02 IFI Increase Margin for PORV Block Valves (Section E8.1). 4 50-280, 281/96003-03 IFI Dynamic Test to Verify Torque Required for 96-inch Pratt Butterfly Valves (Section E8.2).
50-280. 281/96003-04 IFI Static Diagnostic Measurements on Posiseal Butterfly Valves (Section E8.3).
l 50-280. 281/96003-05 IFI Revision of overthrust /overtorque procedure (Section E8.4).
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