IR 05000321/1998006
| ML20196F180 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 11/24/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20196F173 | List: |
| References | |
| 50-321-98-06, 50-321-98-6, 50-366-98-06, 50-366-98-6, NUDOCS 9812040214 | |
| Download: ML20196F180 (11) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGION 11 Docket Nos: 50-321,50-366 License Nos: DPR-57, NPF-5 Report Nos: 50-321/98-06,50-366/98-06 Licensee:
Southern Nuclear Operating Company, Inc. (SNC)
Facility:
E. I. Hatch Plant, Units 1 & 2 Location:
P. O. Box 2010 Baxley, Georgia 31515 Dates:
September 20 through October 31,1998 Inspectors:
J. Munday, Senior Resident inspector J. Canady, Resident inspector T. Fredette, Resident inspector Approved by: P. Skinner, Chief, Reactor Projects Branch 2 Division of Reactor Projects
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Enclosure 9812040214 981124 PDR ADOCK 05000321 G
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EXECUTIVE SUMMARY Hatch Nuclear Plant, Units 1 & 2 NRC Inspection Report 50-321/98-06,50-366/98-06
This integrated inspection included aspects of licensee operations, engineering, maintenance and plant support. The report covers a six week period of resident inspection.
Operations The observed liquid effluent release to the environment was performed in accordance
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with the Offsite Dose Calculation Manual, the discharge permit, and applicable procedures. System trip and flow release set points were conservative (Section O.1.2).
The Unit 2 torus was closed out in accordance with the procedural requirements. No
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system or component leakage was identified. Personnel accountability was emphasized during the torus closeout pre-job briefing (Section O1.3).
The actions taken by the licensee upon receipt of a reactor scram signal on Unit 2 were
appropriate. Although the actual root cause was not determined, the event investigation was thorough (Section O2.2).
Operations management demonstrated conservative decision making by removing the
Unit 2 turbine / generator from service for the replacement of the Stator Cooling Water Y strainer. Maintenance troubleshooting activities identified the specific component causing the stator cooling water flow and pressure problems (Section O 2.3).
Operators demonstrated system awareness and correct procedure usage when they
immediately identified and restored a loss of shutdown cooling on Unit 2 (Section O2.4).
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Maintenance The inspectors concluded that the Local Leak Rate Test team was methodical in the
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performance of the tests associated with the Core Spray check valves. Procedures and work packages were followed and procedure and code requirements were met.
Maintenance and engineering personnel provided evaluative support (Section M1.2).
A Non-Cited Violation was identified for failure of maintenance personnel to follow
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procedures for the removal of a jumper. The independent verification for the removal of an electrical jumper failed to identify the error. The licensee's corrective actions regarding this problem were thorough (Section M1.4).
Enaineerina Field engineering support for the implementation of Design Change Requests on Unit 2
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was effective and thorough. The design implementation engineers coordinated activities directly with craft foremen and provided direct oversight in resolving installation problems (Section E7.1).
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Report Details Summary of Plant Status On September 21, Unit 1 power was reduced to 85% Rated Thermal Power (RTP) to remove the 1 A cooling tower from service to perform age related structural repairs. Reactor power was increased with the tower out of service and 100% RTP was achieved on September 23. On l
September 30 reactor power was reduced to approximately 20% RTP to remove the main i
generator from service to replace a stator cooling water strainer. The maintenance activity was completed and the unit achieved 100% RTP on October 1.
l Unit 2 remained in a Refueling Outage during this report period.
1. Operations l
Conduct of Operations 01.1 General Comments (71707)
Using inspection Procedure 71707, the inspectors conducted reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious.
l Specific events and observations are detailed in the sections below.
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01.2 Operator performance for Liouid Radwaste Effluent Discharae (71707)
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On October 20, the inspectors observed that the radwaste operators performed a liquid
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radwaste effluent discharge in accordance with the requirements of the Offsite Dose i
Calculation Manual (ODCM), discharge permit, and applicable procedures. The I
inspectors also observed that the radwaste control room operators conservatively set the
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radwaste monitor trip set point and the discharge flow rate below that specified on the discharge permit. The inspectors verified alignment of selected local valves associated with the discharge were in the correct positions.
The inspectors concluded that the observed liquid effluent release to the environment I
was performed in accordance with the ODCM, the discharge permit, and applicable l
procedures.
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01.3 Unit 2 Torus and Torus Area Closecut Followina Refuelina Outaae (71707)
The inspectors reviewed procedure 34GO-OPS-029-0S," Torus and Torus Area Closeout," Revision (Rev.) 1, and performed two tours of the torus and the torus area to observe general housekeeping, foreign material control conditions and to inspect systems and components for leakage. The inspectors also attended the licensee's pre-job brief and accompanied an operations and maintenance team into the torus interior.
The inspectors observed during both plant tours that the control of foreign material was in accordance with applicable procedures.
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The inspectors concluded that the Unit 2 torus was closed out in accordance with the
procedural requirements. No system or component leakage was identified. The licensee
stressed personnel accountability during the torus closeout activity.
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O2 Operational Status of Facilities and Equipment O2.1 Review of Decay Heat Removal (DHR) System For Unit 2 Refuelina (71707)
The inspectors reviewed procedure 34SO-G71-0014sS,' Decay Heat Removal System,"
Rev. 6, Edition (Ed) 1, and conducted a walkdown o the system to verify system valves and components were correctly aligned and operating in accordance with procedure.
On September 28, the inspectors observed that system components were operating properly. A representative sampling of the system's electrical and valve line-ups were aligned and operating in accordance with the procedure. The inspectors accompanied a Plant Equipment Operator on rounds to perform checks of the system and verified that his checks were thorough and appropriate.
The inspectors observed portions of the electrical connection, installation, and testing of the temporary standby diesel generator (DG) associated with the DHR system. The inspectors verified that the procedure for starting the temporary DG was available at the DG.
The inspectors did not identify any deficiencies during the system walk down or testing of the temporary standby DG.
02.2 Unit 2 Reactor Protection System (RPS) Actuation Due To Hiah Scram Discharae Volume (SDV) Level (Closed) Licensee Event Report (LER) 50-366/98-003: Valve Position Error Results in Reactor Protection System Actuation a.
insoection Scope (71707)(37551)
On September 23, while Unit 2 was in the Refuel mode, a full RPS actuation occurred due to a high level in the SDV. The inspectors reviewed the activities surrounding this event.
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Observations and Findings The loss of air to the scram air header resulted in the scram valves opening causing a high level in the SDV and subsequent scram.
Operators discovered that a manual isolation valve to the SDV air header pressure
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regulator was closed. The valve was subsequently opened, the scram signal reset and the system was returned to normal. All of the control rods were fully inserted when the scram signal was generated; therefore, the safety function was already completed.
The licensee determined that the event occurred during the time the system valve lineup was being performed. The licensee also investigated the possibility that the isolation
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valve had been closed due to deliberate tampering. The licensee concluded that the
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valve was not purposely mispositioned. However, how the valve got closed was not
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l determined. The licensee checked several other system valves in the area to ensure that l
they were in their correct position. No discrepancies were identified. The licensee J
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documented the event in Licensee Event Report (LER) 50-366/98-003.
The inspectors monitored the investigation activities as they took place. In addition, the system operating procedures and clearances in effect on the system at the time of the i
event were reviewed. No deficiencies were identified.
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Conclusions The inspectors concluded that the actions taken by the operators upon receipt of a reactor scram signal were appropriate. Although the actual root cause was not
determined, the event investigation was thorough. The LER was thorough and detailed.
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Based upon the inspector's review of licensee actions, the LER was closed.
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O2.3 Power Reduction on Unit 1 Due to Stator Coolina Water Problem (71707) (62707)
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The inspectors observed the reactor power reduction and the removal of the Unit 1 j
turbine / generator from service due to stator cooling water problems with the main i
generator. Reactor power was reduced to approximately 20% and the main generator
taken off line to replace a non-isolable Y strainer in the Stator Cooling Water system.
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Trending data indicated a potential system blockage. The licensee had identified the
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most probable cause of the problem to be a clogged Y strainer. The inspectors observed the presence and oversight of operations management in the control room during the power reduction.
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The inspectors were informed by maintenance and engineering personnel that the wire j
mesh in the removed Y stainer was clogged with what appeared to be an oxide coating.
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The strainer was sent offsite to an independent laboratory for an analysis to determine the cause for the oxide coating.
The inspectors verified through the review of the Maintenance Rule Scoping Manual that the 20% power reduction constituted a functional failure of the Stator Cooling Water system. The inspectors were informed by engineering that the system would be l
dispositioned in accordance with maintenance rule requirements. Licensee l
troubleshooting activities identified the specific component causing the stator cooling
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water flow and pressure problems.
l The inspectors concluded that operations management demonstrated conservative decision making by removing the turbine / generator from service for the replacement of the Stator Cooling Water Y strainer.
O2.4 Loss of Unit 2 Shutdown Coolina (71707)
During the performance of procedure 34SV-E51-001-2S,"RCIC Valve Operability," Rev.
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11, Ed 1, the A Residual Heat Removal (RHR) pump tripped which resulted in a loss of
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shutdown cooling. The inspectors observed a loss of shutdown cooling while on a j
routine tour in the control room and assessed operator performance for the system i
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recovery.
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The inspectors observed that the operators immediately recognized the loss of shutdown cooling and entered Abnormal Operating procedure 34AB-E11-001-2S, " Loss of
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Shutdown Cooling," Rev. 5, Ed 1. The operators restored the system within seven minutes. The inspectors verified that the temperature increase of the reactor coolant was negligible.
The licensee determined that the cause of the pump trip was due to the shutdown cooling suction valve,2E11-F009, going closed when a control switch was placed in local control at the remote shutdown panel during the performance of procedure 34SV-E51-001-2S. The hand switch for valve 2E11-F009 was in the closed posiMn at the remote shutdown panel and the valve traveled closed when power was trans1 erred. The licensee determined that the procedure did not have a caution to prevent this type of event from occurring. The inspectors verified that the licensee initiated actions to correct the surveillance procedure.
The inspectors concluded that operators demonstrated system awareness and ccirect procedure usage when they immediately identified a RHR pump trip and restored the system alignment for a loss of shutdown cooling.
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Operator Knowledge and Performance l.
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04.1 Operator Performance Durina Fuel Movement Activities (60710)
I The inspectors reviewed procedure 34FH-OPS-001-0S, " Fuel Movement Operations,"
Rev.18, and observed fuel movement operations from the refueling bridge during part the Unit 2 in-core fuel shuffle and reload.
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The inspectors observed that the Senior Reactor Operator was in continuous communication with control room operators as required by Technical Specifications.
Operator peer reviews were observed for confirming the identification numbers on fuel bundles prior to loading the fuel bridge grapple and fuel placement. The bridge
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operators were alert and attentive to the equipment and were methodical and deliberate in accomplishing each fuel move. A later fuelload verification by the licensee revealed j
that no fuel movement errors occurred.
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Miscellaneous Operations lasues 08.1 (Closed) Inspector Follow-up item (IFI) 50-321.366/97-12-01: Review of Operations.
Maintenance and Enaineerina Actions for Lona-term Resolution of Runnina the EDGs Unloaded or at Low Loads (92700) (92901)
The inspectors reviewed the licensee's Root Cause Analysis summary and engineering recommendations for corrective actions to be implemented by operations and l
maintenance departments. The corrective actions were appropriate to ensure protection i
of the Emergency Diesel Generators when running at less than full load.
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ll. Maintenance M1 Conduct of Maintenance M1.1 General Comments The inspectors observed all or portions of selected maintenance work order activities and found that the work was conducted in a professional and thorough manner. Work packages were present and documentation was complete. Workers were knowledgeable of the work scope and precautions to be used in performing tasks. Radiation protection and safety measures were exercised where appropriate.
M1.2 Local Leak Rate Test (LLRT) and Inservice Testina (IST) of Unit 2 Core Sorav Iniection Check Valves (62707) (37551)
The inspectors reviewed procedures 42SV-TET-001-2S, " Primary Containment Periodic Type B and Type C Leakage Tests," Rev.19,42SV-SUV-003-OS, * Full Stroke Exercising j
of Check Valves," Rev. 4, Ed 2, and observed part of the LLRT, maintenance activities and post maintenance testing.
The inspectors concluded that the LLRT team was methodical in the performance of the LLRT associated with the Core Spray check valves. Procedures and work packages were followed and procedure and code requirements were met. Maintenance and IST engineering personnel provided evaluative support.
M1.4 Refuel Position One-Rod-Out Interlock inocerable Due To Maintenance Error (Closed) LER 50 366/98-004: Personnel Error Results in Condition Prohibited by Technical Specifications a.
Inspection Scoce (62707) (92700)
The inspectors reviewed the licensee's activities surrounding an event in which j
maintenance personnel failed to remove a jumper to restore the refuel position one-rod-out interlock to service.
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Observations and Findinas During the refueling outage thirty-two control rods were to be withdrawn so that the control rod blades or drives could be replaced. To support this maintenance activity the licensee installed jumpers to allow removal of the control rods. Following maintenance, the jumpers were to be removed.
l On October 5, while performing testing for control rod 38-15, operators observed that the l
full-in indicating light did not extinguish when the control rod was withdrawn. Control rod testing was stopped; the control rod was fully inserted and the licensee initiated an
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investigation.
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6 The licensee identified that the jumper for control rod 38-15 had not been removed. The licensee performed an evaluation and concluded that a local criticality may have occurred if control rod 38-15 and an adjacent control rod had been withdrawn simultaneously. The licensee reported the event in LER 50-366/98-004. Although a local criticality may have occurred, the licensee concluded that the increase in radiation exposure to personnel in the drywell would be small and well within the limits of the Radiation Work Permit used to access the area. In addition, the likelihood of operators withdrawing a second control rod i
before theiirst was reinserted was small. Both operator training and procedural restrictions were in place which would have prevented this from occurring.
l The licensee's corrective actions for this event included the following: removing the jumper instaHed for control rod 38-15; cycling each control rod to verify no other jumpers were still installed; issuing a maintenance bulletin describing the event which emphasized i
the proper use of self-verification and independent verification as well as controlling schedule pressure on critical jobs; coaching and counseling the involved technicians on human performance and error prevention skills; and providing training to other maintenance personnel by those involved in this event. The licensee plans to strengthen its process for using jumpers and training was to be added to the continuing training program for maintenance personnel. Maintenance management was to emphasize the expectations for signing off procedure steps as being complete as well as stressing the expectations for supervisors in reviewing jobs for potential errors.
The inspectors reviewed the work package and procedures associated with the activity.
The inspectors observed that procedure 57GM-MEL-003-0S, " Rod Block Bypasses, j
Selective RPIS And Total System," Rev. 3, required the removal of each jumper be i
independently verified by a second individual. Although these steps were signed as having been performed and independantly verified by a second individual, they were never actually performed. The licensee informed the inspectors of a second example where independent verification failed to identify an error. The in.spectors observed that the error was identified and corrected while a system was out of service. Therefore the significance of the error was minimized. This problem was addressed by the licensee's corrective action.
This non-repetitivo, licensee-identified and corrected violation is being treated as Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. It is identified as Non-Cited Violation (NCV) 50-366/98-06-01, Failure To Follow Procedure to Conduct Independent Verification. Based upon the inspector's review of licensee actions, the LER was closed.
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Conclusions
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A NCV was identified for failure of maintenance personnel to follow procedures for the removal of a jumper installed to defeat the full-in signal for control a rod. An independent verification of the work activity failed to identify the error. The licensee's corrective actions regarding this problem were thorough.
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M3 Maintenance Procedures and Documentation M3.1 Surveillance Activities (61726)
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The inspectors observed all or portions of five selected Unit 1 and Unit 2 surveillance
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l activities. The inspectors observed that procedures were correctly used; supervisors l
provided necessary direction and oversight; and procedure and Technical Specification
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l acceptance criteria were met. No deficiencies were identified.
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E7 Quality Assurance in Engineering Activities E7.1 Review of lmolementation of Desian Chance Reauests (DCRs) (37551)
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The inspectors reviewed and observed engineering practices in support of plant implementation of selected DCRs. These included DCR 96-34 " Delete LPCI inverters" i
and DCR 97-40 * Motor Operated Valve Upgrades."
l The inspectors reviewed the DCR packages, installation documentation, and data sheets l
to be used by the DCR implementation engineers. No deficiencies were identified. The i
inspectors observed the installation of most of the electrical cable for the Low Pressure
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Coolant injection (LPCI) motor control centers (MCCs). The implementation engineer
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and electrical foremen involved in the installation coordinated the electrical cable pulling activities directly, and were required to resolve several problems encountered with l
electrical conduit, cable routing, terminationt and component installation.
The inspectors determined that the field engineering support for the implementation of l
these DCRs was effective and thorough. The implementation engineers coordinated
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activities directly with craft foremen, and provided direct oversight in resolving installation
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problems.
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i IV Plant Supoort S2 Status of Security Facilities and Equipment (71750)
S2.1 The inspectors toured the protected area and observed that the perimeter fence was intact and not compromised by erosion nor disrepair. Badge issuance was observed, as was the process for escorting of visitors. Vehicles were searched, escorted and secured
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as described in the applicable procedures. The inspectors concluded that the areas of security inspected met the requirements of the security plan and applicable procedures.
l V. Manaaement Meetinos and Other Areas
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X1 Exit Meeting Summary i
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The inspectors presented the inspection results to members of licensee management at
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the conclusion of the inspection on November 6,1998. The licensee acknowledged the l
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findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
PARTIAL LIST OF PERSONS CONTACTED Licensee Anderson, J., Unit Superintendent Betsill, J., Assistant General Manager - Operations Curtis, S., Unit Superintendent Davis, D., Plant Administration Manager j
Fornel, P., Performance Team Manager l
Fraser, O., Safety Audit and Engineering Review Supervisor Hammonds, J., Engineering Support Manager Kirkley, W., Health Physics and Chemistry Manager Lewis, J., Training and Emergency Preparedness Manager Madison, D., Operations Manager Moore, C., Assistant General Manager - Plant Support Roberts, P., Outage and Planning Manager Thompson, J., Nuclear Security Manager Tipps, S., Nuclear Safety and Compliance Manager Wells, P., General Manager - Nuclear Plant Other licensee employees contacted included office, operations, engineering, maintenance, chemistry / radiation, and corporate personnel.
INSPECTION PROCEDURES USED lP 37551:
Onsite Engineering IP 60710:
Refueling Activities IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations
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IP 71707:
Plant Operations IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901:
Follow-up - Operations
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ITEMS OPENED. CLOSED. AND DISCUSSED i
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50-366/98-003 LER Valve Position Error Results In Reactor Protection System
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Actuation (Section O2.2).
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50-321,366/97-12-01 IFl Review of Operations, Maintenance and Engineering l
Actions for Long-term Resolution of Running the EDGs j
Unloaded or at Low Loads (Section 08.1).
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t 50-366/98-06-01 NCV Failure To Follow Procedure to Conduct Independent l
Verification (Section M1.4)
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I-50-366/98-004 LER Personnel Error Results in Condition Prohibited by l
Technical Specifications (Section M1.4).
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