IR 05000498/1998009
| ML20195F310 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 11/12/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20195F266 | List: |
| References | |
| 50-498-98-09, 50-498-98-9, 50-499-98-09, 50-499-98-9, NUDOCS 9811190235 | |
| Download: ML20195F310 (21) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.: 50-498 50-499 License Nos.: NPF-76 NPF-80 Report No.: 50-498/98-09 50-499/98-09'
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Licensee: STP Nuclear Operating Company ;
Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM 521 - 8 miles west of Wadsworth
Wadsworth, Texas 77483 l Dates: September 6 through October 17,1998 l Inspectors: Cornelius F. O'Keefe, Senior Resident inspector Wayne C. Sifre, Resident inspector Gilbert L. Guerra, Resident inspector Approved By: Joseph I. Tapia, Chief, Project Branch A ATTACHMENT: SupplementalInformation
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9811190235 981112 *
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Q t EXECUTIVE SUMMARY South Texas Project Electric Generating Station, Units 1 and 2 NRC Inspection Report 50-498/98-09; 50-499/98-09 Operations
The inspectors identified that operators did not consistently record Technical Specification entries in the control room log associated with performing surveillances expected to last less than the current shift. This practice was considered acceptable by operations management despite conflict with site requirements for control room loggin Operators were instructed by operations management to log all Technical Specification enLies caused by surveillance performance untillicensee management could address this o.screpancy (Section 01.1).
Operators responded well to a Unit 2 trip caused by loss of feedwater flow to one steam generator (SG) during maintenance. Plant equipment responded as expected during the event. Operators were also observed to control the plant well while shutting Unit 2 down for refueling. Plant operational mode changes were performed in a coordinated and methodical manner, demonstrating effective corrective actions for previous mode change coordination problems (Sections 01.2 and O1.4).
Inspectors concluded that reactor coolant system reduced inventory and midloop operations were performed in a controlled manner by operators who were knowledgeable and experienced in the evolution. Excellent supervisory oversight helped to effectively coordinate site activities and ensure the safe execution of this important evolution. Detailed procedures effectively implemented relevant corrective actions and commitments. Contingency actions were briefed in detail and assigned to specific personnel, and equipment was prestaged. A clear priority for safety was demonstrated when responding to two electrical grounds and in evaluating approaching severe weather for impact on the planned evolution (Section O1.3).
The inspectors and the licensee identified a declining performance trend in removing equipment from service and tagout administration. Corrective actions for two previous violations did not appear to be totally effective in improving performance in this are However, licensee personnel promptly identified the problems, indicating that recent improvement efforts were effective in raising the awareness and questioning attitude toward correct tagouts (Section 08.1).
Maintenance
During the Unit 2 outage, a surveillance performance group of licensed operators planned, scheduled, and performed operations-oriented surveillance tests. The burden on control room operators was reduced as a result. Surveillance group personnel were knowledgeable and well prepared for each test (Section M1.1).
Fuel handling during the Unit 2 refueling outage was performed in a careful manner and completed without error by predominantly newly trained site volunteers. Visual inspections of each fuel bundle as it was offloaded were well performed. The licensee t
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-2-responded appropriately to a damaged fastener on top of a fuel bundle that prevented grappling the bundle. The inspectors identified that informal administrative controls were used to implement changes to the approved core offload sequence (Section M1.2).
Response time testing for a hot leg temperature element indicated an unacceptably slow response time for a resistance temperature detector (RTD). While taking action to remove the RTD from service and preparing to replace it, maintenance and engineering personnel continued to investigate the cause of this problem. With the help of the vendor, the team recognized that actual temperature fluctuations were being misinterpreted by the test instrument as slow system response. The test method was changed slightly and proper system response was verified. Teamwork and a strong questioning attitude were demonstrated in resolving this issue. By finding the actual problem, a properly functioning instrument was not replaced and an unnecessary radiation dose was precluded (Section M2.1).
A maintenance supervisor made a pen-and-ink change to a work instruction for the repair of a low power feedwater regulating valve control circuit that, when implemented, caused the main feedwater regu4 ting valve to close, resulting in a Unit 2 reactor tri The licensee's root cause evaluation did not identify that the change to the work package changed the scope of the work instructions without the procedurally required reviews, resulting in inappropriate work instructions being performed, which was a violation of Technical Specification 6.8.1 (Section M3.1).
Enaineerina a
A system engineer identified that the response time testing procedure for motor-driven auxiliary feedwater pumps contained inappropriate acceptance criteria. Specifically, the sum of allowed individual response times exceeded the total allowed train response time because the acceptance criteria for the pump portion of the testing was too long. The licensee also identified that the pump test used a system configuration different than would be existing during service conditions. The test method was changed to make system configuration match service conditions, and the system yeas successfully demonstrated to be operable. The operability evaluation was thorough and detaile The system engineer demonstrated a good questioning attitude, and engineering performed a prompt and detailed analysis of the operability of the system (Section E4.1 ).
Plant Support
The inspectors noted a declining trend in radiological performance during the Unit 2 refueling outage. The inspectors and licensee personnelidentified numerous examples of poor radiological housekeeping and radworker practices. The high number of personnel contamination events further indicated ineffective controls to prevent the spread of low level contamination. The licensee's response to the higher than expectnd dose rates in the primary plant were insufficient to prevent significantly exceeding the outage exposure goal. Despite the radiation protection department being understaffed for the outage, maintenance work was effectively supported (Section R1.1).
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Report Details Summarv of Plant Status Unit 1 began the inspection period at 100 percent power. On September 12, the main generator was removed from service to facilitate auxiliary transformer repairs. The unit was returned to service later the same day and achieved full power the following day. Following repairs, the main generator was again briefly removed from service to restore the auxiliary transformer to service on September 19. The unit achieved full power the following day and remained there for the remainder of the inspection perio Unit 2 began the inspection period at 100 percent power. On September 22, the plant tripped on low SG water level in SG 2A when Feedwater Regulating Valve 2A closed inadvertently during maintenance work. The unit was restarted on September 23 and reached full power on September 26. Power coastdown for the sixth refueling outage began on September 27, and reached 96 percent power before the' plant was shut down~on October 3 for the remainder of the inspection perio l. Operations
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l 01 Conduct of Operations G1.1 General Comments (71707)
The inspectors used Inspection Procedure 71707 to conduct frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety conscious. Specific comments and noteworthy events are discussed belo The inspectors observed that, during major evolutions affecting one unit, operators in the other unit were fully aware of the status of the opposite unit. The unaffected unit operators provided support without impacting operations in the unaffected unit. During major evolutions, and midloop operations in Unit 2 in particular, the activities in the unaffected unit were carefully limited to avoid impacting the evolutio As discussed in Section 08.1, a continuation of errors implementing tagouts and removing equipment frorn service for maintenance in Unit 2 was note The inspectors observed control room operations during the Unit 1 power reduction and subsequent ascension conducted to allow repairs to the unit auxiliary transformer load tap changer. Control board manipulations performed by trainees were properly supervised by licensed operators. The downpower and startup were performed in a coordinated, deliberate, and controlled manner. Plant equipment performance was goo On October 7,1998, the inspectors noted that a control room log entry declared the accident monitoring containment hydrogen analyzer inoperable because operators were unable to perform the required 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> channel check at 1:25 p.m. on October 6,199 However, the inspectors rioted that the instrument was actually rendered inoperable at
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l-2-8:22 a.m. on October 6,1998, when surveillance testing was begun. Plant Surveillance Procedure OPSP02-CM-4102, " Containment Hydrogen Analyzer ACOT," Revision 4 l
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stated that "this procedure removes from service hydrogen analyzer CM-A-4102." The inspectors questioned why the analyzer was not declared inoperable when the sun rillance test was commenced. Operators stated that the instrument had been con > -dered inoperable when the surveillance was started, but was not logged because
, the istrument was expected to be returned to service before the end of the shift; when i it w acognized that this would not be the case, a log entry was made to indicate the
! int Mnt was inoperable, but the time was not backed up to the surveillance start time l by mou< v. The inspectors verified that no Technical Specification action statements were violate The inspectors discovered that some operators logged only the start of a surveillance, l and considered that, by reference, the Technical Specification actions required could then be determined. However, the inspectors noted that this practice did not
, demonstrate that the required actions were actually recognized and taken. The Unit 1
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operations manager stated that, although many operators made log entries that included l all Technical Specification entries, the existing practice was acceptable. The inspectors noted that Plant Operations Procedure OPOP01-ZO-0022, Revision 16, "olant Operations Shift Routines," Section 6.4.2.2, strongly implied that all entries into Technical Specification action statements shall be logged. Operators were instructed by operations mangers to log all Technical Specification entries caused by surveillance performance untillicensee management could address this discrepancy. The inspectors will review the licensee's response to this issue as an inspection followup item (IFI) (50-498;499/98009-01).
01.2 Ooservations Durina Unit 2 Shutdown for Refuelina On October 3, the inspectors observed the Unit 2 control room operators perform shutdown and cooldown of the Unit 2 reactor in preparation for Refueling and Equipment Outage 2REO6. The inspectors observeu reactor operators performing reactivity manipulations and securing main feedwater pumps in accordance with approved procedures. Mode changes were performed in a cautious, deliberate manne Professional communication was evident throughout the unit shutdown and cooldow The smooth transition from core cooling via SG power-operated relief valves to the residual heat removal system demonstrated that corrective actions for previous .
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01.3 Observation of Unit 2 Reactor Coolant System Midlooo Operations
, insoection Scope (71707)
i The inspectors maintained continuous onsite coverage during midloop operations in Unit 2. The inspectors observed preparations and briefings, walked down temporary systems for water level indication and vacuum filling, and verified that personnel l designated to perform contingency actions were trained and staiioned with necessary
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equipment. Procedures, planning, and oversight were evaluated prior to reduced inventory operations. The licensee's commitments in response to NRC Generic I
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Letter 88-17 were verified to have been implemented. Core decay heat and time to boil calculations were compared to operational assumptions in procedures governing this evolutio b. Observations and Findinas The inspectors observed that the licensee's procedures governing this complex evolution were detailed. The procedures were found to effectively implement corrective actions committed to in response to site and industry events related to midloop operations. Contingency actions were clearly specified and briefed. Designated personnel and equipment were prestaged. Prerequisites appropriately verified that core decay heat and various plant parameters were within acceptable limits and that required ,
plant equipment was availabl l The inspectors noted that operators had recently received training on midloop operations and related industry events. Operators were found to be very knowledgeable and experienced with midloop operation. Operations shift supervision demonstrated proper safety focus when two electrical grounds were identified while preparing to begin reduced inventory operations; the grounds were located and isolated prior to starting reactor coolant system draining. Operators alertly mcnitored all pertiner.+
instrumentation and performed frequent verification of parameters among diverse instruments. The reactor vessel water level sight glass was monitored by an operator in the containment and on a video monitor a the control room. Detailed system drawings and operational data were provided to ensure that operational limits were maintaine Communications were maintained between the control room and important field activities throughout the evolutio Supervisory oversight of the evolution was excellent. Outage management ac"vely provided important coordination of all site activities to ensure that equipment important for midloop operations or contingency actions were maintained available. Senior licensed operators were assigned to supervise the operational aspects of the evolution l and coordinate entry into the primary side of each SG to install nozzle dam Supervisory personnel appropriately evaluated the potential impact of approaching severe weather on the planned start time of the first period of reduced inventory operation The inspectors noted that the licensee made a significant effort to educate all site personnel about the purpose, process, and risk significance of this evolution with the expectation that this would further teduce the potential for problems. Posters, signs, computer, and video presentations were available to fulfil this purpose. During the l evolution, video monitors displayed the progress of the evolution site wide, and periodic announcements on the public address provided reminders for cautio Conclusions inspectors concluded that reactor coolant system reduced inventory and midloop opeistions were performed in a controlled manner t:y operators who were knowledgeabie and experienced in the evolution. Excellent supervisory oversight m.,
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-4-helped to effectively coordinate site activities and ensure the safe execution of this important evolution. Detailed procedures effectively implemented relevant corrective actions and commitments. Contingency actions were briefed in detail and assigned to specific personnel, and equipment was prestaged. A clear priority ;x safety was demonstrated when responding to two electrical grounds and in evaluating approaching severe weather for impact on the planned evolutio .4 Operator Response to Unit 2 Plant Trio (93702)
On September 22,1998, the Unit 2 reactor tripped from 100 percent reactor powe Inspectors promptly responded to the control room to observe the licensee's event response. The automatic reactor trip was caused by a low water level in SG 2A that occurred when SG Feedwater Regulating Valve 2A inadvertently shut during I maintenance. A review of the maintenance activity and the licensee's subsequent !
investigation of the root cause for this event is discussed in Section M3.1 of this report.
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the reactor trip. The operators' response to the reactor trip was veiy good. The unit supervisor directed contro' room operators utilizing appropriate emergency operating procedures while the shift supervisor provided oversight. Formal communication was evident throughout the event. Plant equipment performed as expected with no mechanical failures. Auxiliary feedwater automatically actuated as expected and water i
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level was promptly restored in SG 2 l 02 Operational Status of Facilities and Equipment
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l O Enaineered Safety Feature System Walkdowns (71707) l l
The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following engineered safety feature systems:
- Residual heat removal system (Unit 2) '
- Safety injection accumulators (Unit 2)
- Standby Diesel Generators 12 and 22 (Units 1 and 2)
- Hydrogen recombiners (Unit 2)
- Auxiliary Feedwater Pump 14 (Unit 1)
Equipment operability, material condition, and housekeeping were acceptable in all cases. The inspectors identified no substantive concerns as a result of these inspection The inspectors identified that instrument tubing associated with a pressure transmitter for Safety injection System (SIS) Accumulator 2C was bent. This unprotected small bore tubing was close to a heavy traffic area and equipment laydown area inside the Unit 2 containment. The licensee evaluated the condition and determined that it was l
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bent in a way which could have affected instrument accuracy, so the tubing was promptly repaired.
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-5-During the Unit 2 outage, the inspectors conducted plant walkdowns to verify that work activities did not interfere with the proper operation of required equipment. Generally, work related materials were well situated to avoid blocking passageways or access to important equipment. However, the inspectors identified two instances where scaffolding inside containment was improperly located near safety-related equipmen One scaffold was in contact with an SIS Accumulator 2A instrument valve, and a ladder was tied to another instrument valve on the same accumulator. These deficiencies were pointed out to the licensee and corrected promptly. No additional examples of scaffolding problems were identifie Miscellaneous Operations issues i
08.1 (Open) Violations 50-498/97005-03 and 50-499/97006-01: Two examples of inadequate tagout boundaries and two examples of tagouts vice procedure changes. The inspectors evaluated licensee performance related to control of tagouts during the Unit 2 outage. The licensee had identified a number of errors involving removing equipment from service and tagout administration. Examples included the following:
- The condensate and feedwater system for the Unit 2 startup feed pump was drained without tagging out the auxiliary seal cooling water circulating pumps which were found running dry (Condition Report (CR) 98-15443,98-15439).
- The tagout for the lube oil purification storage and transfer system did not drain the work area for the air side seal oil pump discharge pressure control valve (CR 98-15587).
- An operator incorrectly restored an extra fuse not directed to be restored by the equipment clearance order (ECO) (CR 98-16133).
- The tagout for Train B emergency cooling water system did not tag out equipment supported by the system (CR 98-16121).
- During local leak rate testing, the test coordinator failed to release the ECO to restore the normal instrument air supply as directed by the test '
procedure (CR 98-16119).
- There was inadequate system draining for work on three chemical and volume control system valves (CR 98-15875).
- Tags from the wrong ECO were removed from breakers (CR 98-16360).
l The inspectors discussed these examples with operations management. The licensee
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had identified the declining performance trend in this area and was preparing an action plan to address the issues. The licensee credited the identification of these issues as indication that recent improvement efforts were effective in raising the awareness and questioning attitude toward correct tagouts. The inspectors concluded that, on the basis
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of the above examples of tagout-related errors, corrective actions did not appear to be totally effective in improving performance in this area. These violations will remain open
, pending NRC review of the effectiveness of additional corrective actions by the license ;
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l 11. Maintenance i M1 Conduct of Maintenance l M1.1 Maintenance and Surveillance Observations l inspection Scooe (62707. 61726) ,
The inspectors observed all or portions of the following maintenance and surveillance i activities. For surveillances, the test procedures were reviewed and compared to the i Technical Specification surveillance requirements and bases to ensure that the l procedures satisfied the requirements. Maintenance work was reviewed to ensure that l adequate work instructions were provided, that the work performed was within the scope of the authorized work, and that it was adequately documented. In all cases, the impact
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to equipment operability and applicable Technical Specifications actions were independently verifie Maintenance:
SG 1D power-operated relief valve pressure switch upgrades (Unit 1)
Main steam isolation Valve 2D refurbishment (Unit 2)
Surveillance:
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OPSP03-AF-0007, Auxiliary Feedwater Pump 14 Inservice Test (Unit 1)
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OPSP03-DG-0013, Standby Diesel 21 Loss of Offsite Power - Engineered Safety l Feature Actuation Test (Unit 2)
- OPSP03-DG-0018, Standby Diesel Generator 100 Percent Load Reject Surveillance (Unit 2)
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- OPSP03-SI-0030, Safety injection System Non-intrusive Valve Operability Test i (Unit 2)
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) * OPSP03-SP-00138, Train B ESF Actuation and Response Time Test (Unit 2) Observations and Findinas The inspectors observed that the work performed during these activities was professional and thorough. Work was generally within the scope of the work documen Technicians were experienced and knowledgeable of their assigned tasks, equipment
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I performance, and the significance of the systems being worked. The inspectors I
observed that work supervisors and system engineers were frequently present to monitor job performanc During the Unit 2 outage, the licensee utilized a surveillance performance group of l licensed operators to plan, schedule, and perform operations-oriented surveillance tests. l The inspectors observed that this method was effective in reducing the impact of tests on control room operators while assuring that experienced operators performed the tests. The surveillance group briefed control room operators and completed all documentation, properly obtained permission from control room operators, and kept them apprised of changes in plant equipment status. Surveillance group personnel were knowledgeable and prepared for each test, despite a relatively high testing temp , . a .
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Some of the surveiliance tests, such as the loss of'offsite power, emergency safetyr function, and standby diesel actuation tests, required coordination among various control room operators in order to effectively perform the surveillance. The inspectors noted very good command and control during the performance of these surveillance l test l The inspectors observed that the safety injection system valve operability testing was a complex test affecting all trains of emergency core cooling equipment. The test was ,
performed in an outstanding manner. Pumps were crisply started and stopped to I ensure that the volume of water injected into the reactor was minimized. The test was l l closely coordinated among operations, engineering, maintenance, and the outage surveillance group to support vessel floodup while not exceeding the plant conditions required for the test. Operators were observed to be very knowledgeable of the test sequence and prepared to rapidly shift shutdown core cooling among the three trains of l residual heat remova Conclusions During the Unit 2 outage, a surveillance performance group of licensed operators planned, scheduled, and performed operations-oriented surveillance tests well. The burden on control room operators was reduced as a result. Surveillance group personnel were knowledgeable and well prepared for each tes M1.2 Cordoct of Refuelina Activities Inspection Scope (60710. 71707) ;
l The inspectors observed activities associated with core offload and refueling in Unit The offload and refueling movements were reviewed and compared with vendor recommendations. Radiological controls and postings for areas of the plant that were exposed to higher dose rates during fuel transfers were inspected. The implementation of Technical Specification requirements and prerequisites were verified. Fuel handling was observed inside the reactor containment building and at the spent fuel pool. Decay heat removal capability was frequently verified. Refueling practices were compared to those described in the Updated Final Safety Analysis Report (UFSAR).
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f-8-l Observations and Findinas l The inspectors observed that fuel movements were carefully controlled. A senior l licensed operator was assigned to supervise each evolution. Communications between i
the control room, spent fuel pool, and containment fuel handling area were reliable. The j inspectors noted that many of the personnel performing fuel handling activities were l inexperienced site volunteers under the guidance of contract personnel. Training of these individuals was effective, and no errors or mishaps occurre I l The inspectors verified that plant areas adjacent to fuel handling areas which would be
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1 Fuel Bundle Visual Inspections l The inspectors observed fuel bundle inspections during core offload. These inspections l were conducted before each bundle was transferred to the spent fuel pool storage racks l in order to ensure fuel was undamaged and free of debris. During these inspections, the licensee identified two bundles with slightly damaged grid straps (fuel pin retaining structures). Both bundles were depleted and were not scheduled to be returned to the core. The licensee preliminarily concluded that the grid straps were apparently damaged during fuel handling. The licensee documented the damage and planned an investigation under CR 98-1599 Difficulty Grapling Fuel Bundle U54 During core offload, the licensee was unable to fully lower the refueling mast and l grapple Bundle U54 in Core Location J5. A visualinspection identified a damaged
! spring fastener in the top of the bundle. Fuel handling was secured in order to modify I
the offload sequence and continue core offloa The inspectors reviewed the modified Fuel Transfer Forms (FTF) and discussed changes with the duty reactor engineer. The inspectors verified that the modified offload sequence was in accordance with Plant Engineering Procedure OPEP02-ZM-0005, Revision 6," Internal Transfer of Fuel Assemblies," and maintained neutron coupling with the source range monitors as discussed in vendor documents.
l The licensee was able to remove all damaged and loose parts. The bundle was l successfully grappled in a normal manner and moved to the spent fuel pool. The bundle was depleted and will not be returned to the core. The cause of the damage will be reviewed as an inspection followup item pending completion of licensee and fuel vendor root cause analysis under CR 98-15935 (50-499/98009-02).
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The inspectors observed that, while preparing to reattempt to grapple Bundle U54 after
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removing the loose parts, the duty reactor engineer was preparing to distribute two l
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-9-different FTF change forms, both of which had been approved by the reactor engineering department and the shift supervisor. One contained a movement sequence .
that assumed the attempt to grapple the bundle would be successful and the other '
assumed it would be unsuccessful. The reactor engineer stated that, after distributing both forms, the change to be actually implemented would be controlled verbally. The inspectors were concerned that informal verbal controls were inappropriate and could lead to inappropriate movement of fuel. This concem was discussed with the refueling project manager, who agreed with the inspectors and took action to ensure that only one version of the FTF change was distributed to fuel handlers, Conclusions
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Fuel handing during the Unit 2 refueling outage was performed in a careful manner, and was completed without error predominantly by newly trained site volunteersT Visual '
inspections of each fuel bundle as it was offloaded were well performed. The licensee responded appropriately to a damaged fastener on top of a fuel bundle that prevented grappling the bundle. The inspectors identified that informal administrative controls were used to implement changes to the approved core offload sequence.
! M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Resoonse Time Testina Failure Resolved (37551)
On September 16, the licensee conducted pre-outage response time testing of the instruments and sensors associated with the Unit 2 Over Temperature / Delta Temperature Circuit. Test results for hot leg temperature element TE-430Z indicated an unacceptably slow response time for this RTD. This RTD was one of three circumferentially spaced RTDs which were computer averaged to calculate hot leg temperature.
, The licensee implemented a temporary modification to jumper out the malfunctioning l RTD. The circuit then automatically applied a bias to the averaging circuit to account for l the missing input. The inspectors reviewed the temporary modification and concluded i
that it was consistent with UFSAR statements. The licensee then prepared to replace i the RTD.
Maintenance and engineering personnel continued to investigate the cause of the problem. By evaluating system performance data and discussing test method and p results with the vendor, the investigating team recognized that the affected RTD was
located in a flow area that was subject to incomplete thermal mixing. This resulted in low amplitude temperature oscillations. The test instrument was found to misinterpret the noisy signal as slow system response. To correct the problem, the licensee followed i vendor recommendations to use the test set in an averaging mode which performed i
10 tests to obtain and analyze system response. This method was then validated on
- instruments known to have acceptable responses before retesting the suspect circuit.
l Acceptable results were then obtaine I r
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-10-The inspectors concluded that teamwork and a strong questioning attitude were demonstrated in resolving this issue. By finding the actual problem, a properly functioning instrument was not replaced and an unnecessary radiation dose was preclude M3 Maintenance Procedures and Documentation M3.1 Unit 2 Reactor Trio Durina Maintenance Insoection Scope (62707. 93702) l On September 22, the Unit 2 reactor tripped from 100 percent power when SG Feedwater Regulating Valve 2A closed during~ maintenance workc in response to this event, CR 98-14552 was written and an event review tearri Wasa~ssembled to determine ,
the root cause. The inspectors reviewed and discussed CR 98-14552 and the Event i Review Team report and interviewed personnel involved in the even l Observations and Findinas
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Through document review and interviews, the inspectors determined that instrumentation and controls technicians were utilizing Plant Maintenance Procedure OPMP08-FW-0551, Revision 2, " Steam Generator Level Control Loop Calibration,"in accordance with Work Order BS-354091 to replace a card in the control circuit for Low Power Feedwater Regulating Valve 2A. .The work irstructions had originally instructed the technicians to calibrate the replacement card in accordance with steps in Plant Maintenance Procedure OPMP08-FW-0551, place the replacement card in service, and document all further plans for troubleshooting. The instrumentation and controls supervisor changed the work order instructions to incorporate additional sections of the procedure. The intent of the change was to utilize a portion of an approved procedure for instrument removal, restoration, unreliable indications, and precautions. However, the supervisor failed to recognize that the change resulted in the placement of jumpers in the control circuits for both the SG 2A low power feedwater regulating valve and the normal SG 2A feedwater regulating valve which caused the valves to shut. The low power valve was not in senrice. However, shutting the normal feed regulating valve while it was controlling feedwater flow resulted in loss of feedwater flow to the associated SG, with a resulting reactor trip. The licensee's event evaluation identified the use of the wrong procedure steps as the root caus The inspectors noted that the change to the work Instructions was made as a
" pen-and-ink" change. Per Plant General Procedure OPGP03-ZA-90, Revision 19,
" Work Process Program," pen-and-ink changes were intended for minor changes that did not alter the scope or intent of a work package. The inspectors determined that by changing the work instruction to include the placement of jumpers in the control circuit of both the low power feedwater regulating valve and the main feedwater regulating valve,
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the work scope was changed. Thus, the inspectors concluded that by using an l inappropriate method to change the work scope, the supervisor precluded any review
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-11-that might have identified the error. The inspectors also found that in their evaluation the licensee did not identify the work instruction change as a change in scope, the method of change as inappropriate or a contributing cause to the even Technical Specification 6.8.1 states, in part, that written procedures shall'Je established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33 requires that maintenance that can affect the performance of safety-related equipment be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstance The implementation of a change to Work Order BS-354091 resulted in inappropriate work instructions and was considered a violation of, Technical Specification 6.8.1 -
.(50"499/90009-03). This violation was not considered for enforcement discretion because of the significance of the event and because the licensee's root cause investigation was superficial and failed to identify and address a significant contributing Caus Conclusions A maintenance supervisor made a pen-and-ink change to a work instruction for the repair of a low power feedwater regulating valve control circuit that, when implemented, caused the main feedwater regulating valve to close, resulting in a Unit 2 reactor tri The licensee's root cause evaluation did not identify that the change to the work package changed the scope of the work instructions without the procedurally required reviews, resulting in inappropriate work instructions being performed, which was a violation of Technical Specification 6. . Enaineerina E4 Engineering Staff Knowledge and Performance E Licensee Identified Inaoorooriate Acceotance Criteria for Auxiliarv Feedwater (AFW)
Train Response Time Testina (37551)
A system engineer reviewing the response time testing for the AFW system identified that the test assigned 45 seconds as an acceptance criteria for the motor-driven AFW pumps to start and reach rated flow. However, the UFSAR allowed 60 seconds for the entire system to identify a low-low SG condition, start the associated standby diesel generator, shut the output breaker, sequence the loads, start the pump, and develop rated flo The licensee evaluated historical performance data, which indicated that the total sequence time was very close to the 60 second time for each train. However, the licensee also identified that the pump test used a system configuration different than would exist during service conditions. This resulted in not reaching rated flow until a normally open valve stroked open, which required about 20 seconds. The test method
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-12-was changed to perform the test with the flow control valve open, and test results indicated the pump reached rated flow in less than 2 seconds, as expected. Based on the above, the lic ansee completed a thorough operability evaluation that concluded that the pumps were aperabl l l
The inspectors reviewed the test procedure, historical data, and operability evaluation, as well as observing the pump test. The inspectors c:ncluded that the evaluation was thorough and detailed and appropriately concluded that the system was operable. The system engineer demonstrated a good questioning attitude, and engineering performed a prompt and detailed analysis of the operability of the syste The inspectors reviewed the revised Procedure OPSP03-SP-0013B," Train B ESF Actuation and Response Time Test," Revision 3. This revision modified the testing method to fully open the pump discharge valve before 3 .trting the pump. The time to reach a 550 gpm flow rate was then measured. The revised acceptance criteria of 16 seconds was appropriate to ensure a channel response time within the 60 seconds allowed. The inspectors observed the test, which was successfu E8 Miscellaneous Engineering issues E8.1 (Closed) Licensee Event Report (LER) 50-498/98006-00 and -01: Failure to meet the requirements of Technical Specification Surveillance 4.0.5 for containment ; solation l check valves. This event was discussed in detailin NRC Inspection Report 50-498;499/9808. Revision 1 of this LER was issued to report that six additional containment isolation check valves in Unit 1 were not tested as required. The additional !
valves were the high head and low head safety injection pump discharge check valves l in all three trains. These valves were identified by Quality Assurance personnel during a review of the original issue. The original scope review was too narrow in scope. As a ;
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result, an additional review was performed for all containment piping penetrations to ensure testing requirements were properly identified and completed within the required periodicity. No additional omissions were identifica. The licensee declared tne affected l penetrations inoperable and performed the required testing satisfactorily within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> The cause of the event was inadequate tracking and scheduling of testirg requirement The ASME Section XI testing was being satisfied by performing local leak rate testing per 10 CFR Part 50, Appendix J. However, the ASME testing was not separately I tracked. When perfotmance based Appendix J was approved for South Texas Project per Option B, the licensee failed to recognize that the ASME Section XI tests were affected by the chang In response to this event, the licensee completed a thorough review of all containment isolation check valves to identify functions, testing requirements, and last completion dates. The licensee was in the process of developing a computer based scheduling system to schedule and track completion of testing for all testing requirements separately. Additionally, the Unit 2 valves requiring testing during the outage were identified and scheduled prior to the start of the outage. A review of allinservice testing l
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l requirements will be completed during February 1999 to ensure each requirement is uniquely identified and tracked. Also, a comprehensive review of ASME Section XI program-related changes during the last 5 years to identify impact on other programs I was scheduled to be completed in January 1999. Licensee corrective actions in !
response to this issue were broad and comprehensive. This item is closed.
l E8.2 (Closed) Escalated Enforcement item 50-498/98008-01: Failure to meet the l l requirements of Technical Specification Surveillance 4.0.5 for containment isolation check valves. As discussed in Section E8.1 above, licensee corrective actions in l response to this issue were broad and comprehensivo. The additional six valves not l identified during the initial review of this issue were identified by the licensee upon more i careful review and were thus, not considered to be a separate occurrence. Failure to i test these valves was of minimal safety significance. In accordance with the NRC l Enforcement Policy (NUREG 1600), Section Vll.B.1, this licensee identified and I i
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corrected violation will not be cited (50-498/98009-04).
l E8.3 (Closed) LER 50-499/98003: Control room ventilation emergency makeup filter system j exceeding an allowed outage time. On July 6,1998, the licensee declared the Train B l control room emergency makeup filter system inoperable as of April 16,1998. This was l done as a result of discovering that the halide detector used to verify filter performance l during the surveillance on that date was in an out-of-calibration condition. Corrective j actions were taken and the Train B makeup and cleanup filtration system was declared
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operable on July 7,1998. No concerns were identified during the review of this issu This item is closed.
l IV. Plant SUDDort R1 Conduct of Radiation Protection and Chemistry Activities t
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R Observations of Radioloaical Performance Durina the Unit 2 Outaae Inspection Scope (71750)
j The inspectors observed radiation protection activities and radworker practices during maintenance observations and walkdowns of the Unit 2 reactor containment building
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during its sixth refueling outage. Also CRs and daily status reports were reviewe !
Observations were discussed with radiation protection department personnel, Observations and Findinas During walkdowns of the reactor containment building, the inspectors noted examples of poor radiological work practices. Identical bags marked as SG equipment were inconsistently labeled; some had radioactive material tags and others did not. Several vacuums used for radiological work in the reactor containment building were found
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stored without covers on the hoses to prevent the release of contamination.
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Housekeeping was poor with regard to protective clothing in the reactor containment I
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g ** f-14-building. Unused protective clothing was noted throughout containment, while the availability of clean protective clothing was short due to laundry problems. Other uncontrolled items noted in containment inc uded tape balls and other paper tras The inspectors noted that at the -11 feet level inside containment, ventilation air flow was from the contaminated area inside the biological shield to the clean area outside the wall. The inspectors discussed their concern regarding the potential for the spread of contamination under these conditions with radiation protection personnel. Radiation protection personnel stated that they were aware of the problem, and had attempted to minimize the potential spread of contamination by frequently cleaning the affected area rather than correcting the ventilation flow. The number of reactor containment fans in use was also minimized commensurate with industrial safety. As of the end of the inspection period, the inspectors noted that radiation protection had not documented the condition or discussed options with engineering personnel. This issue will be tracked as an IFl to review the effectiveness of licensee practices and any corrective actions during the next plant refueling outage. (50-498;499/98009-06)
A high number of personnel contaminations occurred during the outage. In the first 2 weeks of the outage,364 personnel contaminations were logged. The inspectors noted that this figure was limited to contamination events affecting the face, skin, or personal clothing greater than 100 corrected counts per minute; a much larger number of personnel contamination monitor alarms occurred. The inspectors observed long lines at the radiological controlled area exit due to the many personnel contamination monitor alarms which took extra radiation prntection statf for response, directing personnel traffic, and performing decontamination activitie The inspectors noted that radiation protection personnel effectively supported outage work. However, the inspectors observed that few personnel were available to perform routine cleaning in radiologically clean areas to prevent the spread of low level contamination. Licensee personne! indicated that this was due to a shortage of available contract radiation protection and decontamination personnel. Radiation protection management acknowledged that this shortage of staff reduced the effectiveness of the radiation protection department during the outag Outage dose rates were higher than expected. Dose rates in the SG primary side and inside the biological shield were approximately 50 percent higher than expected. This contributed to exceeding the external exposure goal by more thar 30 percent. The higher dose rates were attributed in part to the reactor trip prior to the outage, in addition, the licensee identified several conditions indicative of poor health physics practices and failures to follow work instructions by radworkers, including:
- Several examples of forgetting or leaving behind thermoluminescent or electronic dosimetry at access control or different work control points. On one occasion a radworker did not log out of the radiological controlled area or notify radiation protection staff;
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Examples of radworkers performing self decontamination, using poor protective clothes removal and contamination control practices;
Materials control problems such as radioactive trash causing higher radiation levels; and
- The creation of unexpected radiation area The inspectors noted that the radiation protection department personnel actively pursued the identification of radiological problems. However, these efforts were not totally effective. Corrective actions were narrowly focused in most cases. The declining performance trend in the radiation protection program was evident during the Unit 2 outage, Conclusions The inspectors noted a declining trend in radiological performance during the Unit 2 refueling outage. The inspectors and licensee personnelidentified numerous examples !
of poor radiological housekeeping and radworker practices. The high number of l personnel contamination events further indicated ineffective controls to prevent the spread of low level contamination. The licensee's response to the higher than expected dose rates in ihe primary plant were insufficient to prevent significantly exceeding the outage exposure goal. Despite the radiation protection department being understaffe i for the outage, maintenance work was effectively supporte !
F8 Miscellaneous Fire Protection issues F8.1 (Closed) Violation 50-498/98003-01: Failure to restore five fire hose stations inside containment to service following system modification. Training was conducted on this j event during operator requalification. Licensee management issued expectations for j monitoring the status of the fire protection system on the fire protection computer ,
monitor in each control room. Additional corrective actions to address programmatic '
problems with tagouts were taken, as discussed in Section 08.1. The inspectors walked down the fire protection system inside the Unit 2 containment after the licensee had completed all outage maintenance on the system and verified that the system was properly aligned and that system equipment was in good condition. Additionally, during the period when portions of the system were out of service for testing, the inspectors verified that appropriate compensatory measures were established in accordance with the fire protection program. Corrective actions for the violation were appropriate and I effective. This item is close . -- . .-
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16-l V. Manaaement Meetinas i
l X1 Exit Meeting Summary i
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The inspectors presented the inspection results to members of licensee management on October 20,1998. Management personnel acknowledged the findings presented. The i inspector asked whether any materials examined during the inspection should be considered l proprietary. No proprietary information was identifie
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ATTACHMEN_I t SUPPLEMENTAL INFORMATION
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PARTIAL LIST OF PERSONS CONTACTED Licensee P. Arrington, Nuclear Assurance and Licensing T. Cloninger, Vice President, Nuclear Engineering W. Dowdy, Manager, Plant Operations Unit 2 S. Eldridge, Quality Assurance Consultant J. Groth, Vice President, Nuclear Generation M. Kanavos, Manager, Mechanical-Civil Design
' C. Keen', Shift Supervisor '
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A. Kent, Manager, Electrical / instrumentation and Controls System +.wmm -
D. Lazar, Director, Nuclear Fuel and Analysis F. Mangan, Vice President, Plant Services G. Parkey, Plant Manager, Unit 1 J. Phelps, Manager, Unit 1 Operations l
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G. Powell, Manager, Health Physics V. Simonis, Manager, Ptoduction Support K. Work, Nuclear Assurance and Licensing, Engineer l UhQ D. Powers, Chief, Maintenance Bran h, Region IV I M. Shannon, Radiation Specialist, Region IV l
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R. Kopriva, Senior Project Engineer, Region IV l l
l IN^.,PECTION PROCEDURES USED
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IP 37551: Onsite Engineering ;
l IP 60710: Refueling Activities i l lP 61726: Surveillance Observations IP 62707: Maintenance Observation l lP 71707: Plant Operations IP 71750: Plant Support IP 92700: Onsite Followup of Written Reports of Nonroutine Events at oower Reactor
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Facilities
- IP 92902: Followup - Maintenance )
l ~lP 92904: Followup - Plant support l lP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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l ITEMS OPENED. CLOSED. AND DISCUSSED
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Ooened 50-498;499/98009-01 IFl inconsistent control room log entries for Technical Specification actions during short duration surveillances 50-499/98009-02 IFl Review results of licensee and vendor root cause for damaged fuel bundle structures 50-499/98009-03 VIO Inappropriate work instructions'cause'ieactor trip on loss
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of feedwater flow to one SG ' - ' '
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50-498/98009-04 NCV .. Failure to Perfbrm Ah% ' ' sAE Code Chick Val , j 50-498/98009-05 IFl Potential for the spread of contamination due to verification flow Closed l 50-498/98003-01 VIO Failure to restore five fire hose stations inside containment to service following system modification ,
j 50-498/98006-00 and LER , Failure to meet the requirements.of,Technicalm
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01 Specification Surveillance 4.0.5 for containment isolation check valves 50-498;499/98008-01 eel Failure to Perform ASME Code Check Valve Testing l
50-499/98003 LER Makeup and cleanup filtration system exceeding an
! allowed outage tim /98009-04 NCV Failure to Perform ASME Code Check Valve Testing Discussed w <
< m 50-498/97005-03 VIO Two examples of inadequate tagout boundaries 50-499/97006-01 VIO Two examples of inappropriate use of tagouts vice procedure changes
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