IR 05000346/1979019
| ML19209A436 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 08/07/1979 |
| From: | Beyes L, Tambling T, Warnick R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML19209A383 | List: |
| References | |
| 50-346-79-19, NUDOCS 7910030865 | |
| Download: ML19209A436 (13) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT
REGION III
Report No. 50-346/79-19 Docket No. 50-346 License No. NPF-3
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Licensee: Toledo Edison Company Edison Plaza 300 Madison Avenue Toledo, OH 43652 Facility Name: Davis-Besse Nuclear Power Station, Unit 1 Inspection At: Davis-Besse Site, Oak Harbor, OH Inspection Conducted: May 29-31, June 1, 4-8, 11-22, 25-30 and July 2-8, 1979
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h D h ~l 3 Inspectors:
T. N. Tambling (Jun 7-8, 1
1979)
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L. A. Reyes
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29-31, June 1, 11-17, 25-29, 1979)
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e 4-8, 11-15, 27-30, 1979)
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Y7l~lR ak (June IJ-22, July 2-8, 1979)
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(May 29-31, June 19-21, 1979)
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(July 2-7, 1979)
RFid d Approved By:
R. F. Warnick, Chief g/y/yg
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Reactor Projects Section 2 1 0 8 6
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Inspection Summary Inspection on May 29-31, June 1, 4-8, 11-22, 25-30 and July 2-8, 1979 (Report No. 50-346/79-19)
Areas Inspected: A routine, unannour
' inspection of followup on licensee event reports, a special inspection cow...n the THI-2 incident, the o
licensee's response to IE Bulletin 79-05A and 79-05B and the Shutdown Order. The inspection involved 467 inspector-hours onsite by six NRC inspectors.
Rasults: Of the four areas inspected, no items of noncompliance or devi-ations were found in three areas; two items of apparent noncompliance were identified in the other area (infractions - failure to follow procedure - Paragraph 5; and failure to change documents.i timely manner - Paragraph 3.c).
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DETAILS 1.
Persons Contac'._ed T. Murray, Station Superintendent B. Beyer, Assistant Station Superintendent P. Carr, Maintenance Engineer S. Quennoz, Technical Engineer G. Wells, Administrative Coordinator
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D. Miller, Operations Engineer D. Briden, Chemist and Health ?hysicist J. Hickey, Training Supervisor L. Simon, Operations Supervisor The inspectors also interviewed other licensee employees, including members of the technical, operations, maintenance, I&C, training and health physics staff.
2.
LER 79-50 The licensee reported by telephone and facsimile transmission on April 23, 1979 and via a 14 day written report dated May 4, 1979 an unplanned reactivity insertion of + 0.59% J K/K during the Reactor Coolant System (RCS) fill on April 21 and 22.
Davis-Besse operations personnel commenced the Reactor Coolant System (RCS) fill at 1905 hours0.022 days <br />0.529 hours <br />0.00315 weeks <br />7.248525e-4 months <br /> on April 21, 1979.
It was planned that 47,000 gallons of water from Clean Waste Receiver Tank (CWRT)
1-1 (1237 ppm boron concentration) would be pumped into the RCS (1259 ppm boron concentration) to achieve a final RCS boron concen-tration of 1246 ppm.
Midwaf through the fill the Davis-Besse Chemistry Lab reported that the RCS boron concentration was 1198 ppm.
Operations persennel requested another RCS sample to verify the boron concentration.
The boron concentration of the second sample was 1194 ppm, essentially the same as the first time. At this time the RCS fill was stopped to find the cause of the RCS boron concentration reduction. Although the RCS boron concentration dropped to 1198 ppm the + 0.59%
ti K/K reactivity insertion did not result in a shutdown margin less than the minimum TS requirements of 1.0% o K/K.
The inspector reviewed the licensee actions and evaluations with respect to this event to verify that the event was reviewed and corrective action was taken in accordance with regulatory require-ments. The corrective actions being taken are:
a.
Modification of " Filling and Venting of the RCS Operating Procedure," SP 1103.02 to include sampling the RCS boron concentration at four hour intervals during the fill and 1086 M
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immediately stopping the fill if any RCS boron concentration discrepancies arise. The procedure has also been revised to close the demineralized water to Primary Makeup System Iso-lation Valve, DW-66, when lining up the Clean Waste Receiver tank to the RCS for filling.
b.
Maintenance Work Order 79-1586 was issued to troubleshoot and repair Boron Batch Flow Controller Valve MU-39.
c.
Review of the details of the incident with all operations
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personnel.
This item will be remain unresolved pending the completion and fin 1 review of the licensee's corrective action.
(50-346/ 79-19-01)
3.
IE Bulletin 79-05A and 79-05B a.
Procedure for Early Notification of NRC The licensee had changed (Major Modification Request M-3109)
Emergency Plan AD 1827.00 to require the Shift Foreman to assure the NRC is notified within I hour any time the reactor is not in a controlled or expected condition of operation. The Shift Foreman or his designated representative shall then maintain continuous communications with the NRC using the designated (red) NRC phone.
Discussion with licensee personnel indicate they are knowledge-able abo:t this change to the Emergency Plan.
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b.
Guidance for Securing RCP's The licensee has included guidance in procedures AB 1203.05.1 and EP 1202.06.10 for securing RCP's when vibration reaches 30 mils.
c.
Verificat in of Engineered Safety Feature (ESF) Lineups To verify the adequacy of alignment of the ESF the inspectors independently verified the valve and breaker position for one train of each of the following systems.
Core Flood - SP 1104.01 Decay Heat and Low Pressure Injection - SP 1104.04 Containment Spray - SP 1104.05 High Pressure Injection - SP 1104.07 Auxiliary Feedwater System - SP 1106.05 Emergency Diesel Generators - SP 1107.11 Locked Valve Verification Periodic Test - PT 5186.01 1086 l^'
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As a result of this independent verification the inspector noted that not all valves are labeled (identification tag) as to number. The licensee was noting and listing valves without labeling so that labels could be provided in the future.
Some labels are plastic covered paper tags which will be lost or destrcyed as the plant ages.
Not all breakers in motor control centers are labeled. An example noted was MCC F11E and E12E, where about half the breakers are not permanently labeled.
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During the valve lineup of the Auxiliary Feedwater System vent valve AF81 was found open. The valve was subsequently closed.
The licensee had previously lined the system up in preparation for startup.
During the lineup of the high pressure injection system a previously unidentified pressure tap valve was found on the pump suction. This valve was not contained in the lineup procedure or on the print for the system (M-033, Rev. 33).
During the valve lineup of the decay heat system the inspector noted that there was no valve DH 100A installed in the system as shown on print M-033, Rev. 33.
The valve lineup verifi-cation conducted by the licensee using procedure SP 1104.04.9 listed DH 100A as closed. The lineup check sheet completed about June 22, 1979 by the licensee in preparation for startup had this valve initialed to indicate it was in the closed position.
The inspector observed a note in relay cabinet RC 2826 (EL 565 near MCC E22B) that indicated TDR-2 was not mounted or wired as shown on connecting diagram E 547, Rev. 5 and that the wiring did not match elementary drawing E49B, sheet 25, Rev. 7.
The note was dated June 21, 19~8.
Investigation by the licensee revealed TDR-2 had been installed using FCR 77-155 per MWO 77-1418 which had been lost.
WR 77-1295-15 was issued which verified the FCR installations had been completed. The WR was signed off on October 25, 1977. E49B, Rev. 7 contained no reference to this FCR or incorrect installation of TDR-2.
The above examples concerning valve DH 100A and relay TDR-2 suggest that the licensee has problems in maintaining up to date prints that reflect the current status of systems (valves installed not on print, valve on print not installed, and relay not on print). This appears to be in noncompliance with 10 CFR 50, Appendix B, Criterien V requirements to follow procedures in that procedure CAP-2060 of the Nuclear Quality Assurance Manual requires that approved changes be incorporated into documents associated with the change in a timely manner.
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As a result of concerns raised by the RIII inspectors, on July 7, 1979 the licensee walked down the HPI piping to demonstrate on a sampling basis that there were no major items that existed in safety system which would prevent them from functioning in an emergency because of the problem with "as built" prints.
No additional items of noncompliance ar deviations were identified.
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Shutdown Order a.
Background By order dated May 16, 1979 the licensee was directed by the NRC to take certain actions with respect to the station.
The Commission found that operation of the plant should not be resumed until design modifications and changes in operating procedures were satisfactorily completed. All actions were reviewed by onsite inspectors and other members of the staff.
The Shutdown Order was lifted on July 6, 1979 after the NRC staff was satisfied with the corrective actions taken.
b.
Training (1) Training Plan The Region III inspector verified that requirements for Licensed Operator training, as set forth in TECo letter No. 512, dated May 26, 1979, Lowell E. Roe to Robert W. Reid, were satisfied and that proper documentation of the training was maintained.
(2) Sequence of Events at TMI-2 The presentation was made by training department personnel to all operations personnel to provide them with an under-standing of the significance of such an event at Davis-Besse.
(3) Region III Review of TMI Event A presentation was made by RIII inspectors to all licensed operators on the areas of concern about the TMI sequence of events and the need for correct operator action during emergencies.
(4) B&W Simulator Training All Licensed Operators participated in the B&W Simulator Training Program for the TMI-2 event. Each operator performed the control functions in situations similar to the TMI-2 event.
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(5) Procedures and Procedure Revision Review All licensed operators reviewed the procedural changes and were audited on crew by shift foremen to insure covered areas were sufficiently understood.
In addition, 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of additional instruction were given on procedural changes.
(6) Formal Classroom Instruction Instruction was givea to all licensed operators as per
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Davis-Besse training document " Training Approach to Systems and Procedure Update Post TMI-2."
(7) Written Examination An examination was given to all licensed operators on material covered during the entire training program. A grade of 90% was established as the minimum satisfactory grade.
If a grade of 90% was not received, additional time was given to study for a -econd examination.
(8) Oral Examination An oral examination was given to all licensed operators in the subject areas mentioned above on items (1) through (6).
(9) Hours of Instruction and Review Sequence of events at TMI 2.0 Hours
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Region III I&E Critique of TMI 1.0 Hours
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B&W Simulator Training 4.0 Hours
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On Shift Revier With Shift Foreman 4.0 Hours
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On Shift Review by Operator 4.0 Hours
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Formal Classroom Instruction 16.0 Hours
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On Shift Emergency Procedures
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Review 8.0 Hours Total Hours of Instruction and Review 39.0 Hours Written Examination 1.0 Hours
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Oral Examination 1.0 Hours
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The hours shown above are the minimum of which all licensed operators participated in the post-TMI training.
(10) Training Evaluation The formal training was taught by t. raining department personnel and the Nuclear and Performance Engineer. The
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inspector attended the classes on May 30 and 31, 1979.
The material presented was well received and the operators had actively participated in the discussions.
The overall training program appears to be excellent. The only adverse comments received by the inspector, from participants were that the formal procedure update review was quite fast.
However, subsequent questioning of the operators and the exam-ination results indicated that the procedure update reviews were satisfactory.
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c.
Review of Facility Changes Facility change records for the following changes were reviewed and it was verified that in each case reviews and approvals for implementation were obtained in accordance with the licensee's procedure for facility changes (AD 1845.00 - Changes, Tests and Equipment). Additional items ere verified as noted below.
(1) FCR 79-169 (Rev. A).
This item involved raising the relief setpoint for the pressurizer pilot operated relief valve from 2255 psig to 2400 psig and changing the valve closure setpoint to 2350 psig. The change was implemented (in conjunction with FCR 79-170) to reduce the probability of relief valve operation during anticipated transients.
The inspectors reviewed the facility change request package including the involved maintenance work order (MWO-IC-79-169)
and the results of post implementation testing performed on May 24, 1979 in accordance with PT 5164.02, Phase II (Pressurizer Relief Valve Periodic Test).
(2) FCR 79-170. This item involved lowering the reactor protection system high pressure trip setpoint from 2351.4
+ 0.00 -2.80 psig to 2296.4 +0.00 -2.80 psig. The change was implemented (in conjunction with FCR 79-169 (Rev. A))
to reduce the probability of operation of the pressurizer pilot operated relief valve during anticipated transients.
The inspectors reviewed the facility change request package including the involved maintenance work order (MWO-IC-79-lic)
and the results of post implementation testing performed during the period May 26-30, 1979 in accordance with ST 3030.02 (RPS Monthly Functional Test).
(3) FCR 79-176. This item involved the installation of a hard wired reactor trip on loss of feedwater or a turbine trip.
The inspectors reviewed the facility change request package and viewed the physical installation.
In addition, post implementation testing performed during the period June 11 and 12, 1979 per ST 5030.02 (Test Procedure for the Control Grade Anticipatory Reactor Trip System) and ST 5030.12
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(Channel Functional Test of the Reactor Trip Module Logic
and Control Rod Drive Trip Breakers) was witnessed and the results of post implementation testing performed on June 13, 1979 per ST 5030.13 (Channel Functional Test of Manual Reactor Trip) were reviewed.
Testing of the Anticipatory Reactor Trip System (ARTS) was completed as of June 15, 1979. No test deficiencies were noted. Testing of the Loss of Feedwater Reactor Trip Circuitry was accomplished by simulating a reverse dif fer-
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ential pressure on the feedwater check valves and verifying the CRD Breakers opening. The Steam and Feedwater Rupture Control System (SFRCS) which uses the same differential pressure switch to sense a loss of feedwater was not degraded in any way as demonstrated by ST 5031.14, SFRCS Monthly Surveillance Test. Testing of the Turbine Reactor Trip Circuit was accomplished by simulating the turbine on line with the EHC Simulator, tripping the Master Trip Solenoid and verifying the CRD Breakers opening.
The Block Switch to bypass the Turbine Reactor Trip was func-tionally tested. Additionally, all computer and annunciator alarms associated with the ARTS installation were tested.
The Reactor Protection System and Manual Reactor Trip were not degraded by the incorporation of the two additional reactor trips as demonstrated by ST 5030.12, Channel Functional Test of RX Trip Module Logic and CRD Trip Breakers, and ST 5030.13, Channel Functional Test of Manual Reactor Trip.
Testing of ARTS has been incorporated into a new procedure, PT 5155.02, ARTS Monthly Functional Test.
(4) FCR 77-221.
This item involved the installation of a resistor to the Auxiliary Feedwater Pump Turbine control to improve the precision of the governor speed changer motor.
Testing of Auxiliary Feedwater Pumps 1-1 and 1-2 was completed as of June 21, 1979, under a test procedure incorporated as a temporary modification to ST 5071.01.
No deficiencies were noted. The Auto Essential Level Control Circuitry provides the governor speed changer motor with pulses of varying duration depending on OTSG level error. Drifting of the speed changer motor will have a deleterious effect on the level control system by continually forcing the governor to hunt for a specified speed setting.
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Dynamic braking allows the motor field's residual magnetism to generate a current flow through the braking resistor and produce a counter torque to effectively stop the motor. Because of the precision in which the motor is stopped with dynamic braking, it would take significantly more pulses to run the governor from the low to the high speed stops (or vice versa) than when the motor inertia was unchecked and drifting occurred. The test functionally proved this for both the opening and closing directions at all pulse lengths.
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Test results demonstrated that on the average of 250% more
" braked" pulses were required to reproduce the same governor movement as when motor coasting existed, permitting much finer control characteristics for the governor.
(5) FCR 79-188. This item involved the installation of sonic type flowmeters to measure the Auxiliary Feedwater Flow to each OTSG. The inspectors reviewed the facility change request package and witnessed portions of the flow cali-bration verification. The first attempt to calibrate the Auxiliary Feedwater Flow to OTSG levels rise for AFW pump 1-2 failed. The flowmeter did not register any flow, although the rise of water level in OTSG 1-1 indicated that water was being injected into the OTSG.
Calculations of flowrate based on OTSG level rise indicated a flowrate of approximately 1306 gpm. This flowrate is in excess of the 500 gpm fillrate limit contained in B&W Limits and Precautions Document DP 1101.01, Section 1..09-E, Rev. I dated February 11,1976. The inspector requested from the licensee an analysis to determine that no damage resulted from flowrate of this magnitude. The licensee requested that B&W analyze the consequences of violating the Auxiliary Feedwater Flow limit.
In a letter dated June 21, 1979 (Ref. No. 620-0014-55) B&W documented the basis for the flowrate limit of 550 gpm and concluded that flowrates under 1320 gpm, based on limiting water impingement veloc-ities on the OTSG tubes to 5 Ft/Sec, are conservative and acceptable for steam generators with internal feedwater headers.
After repairs of the flowmeter for AFW pump 1-2 was com-pleted, the calibration test was repeated for both pumps and the acceptance criteria were met.
The testing was performed under a test procedure incorporated as a temporary modification (T-3820) to proc. dure ST 5071.01.
d.
Walk Through of Selected Procedures During the period June 13 and 14, 1979, the inspectors accom-panied by several licensed reactor operators walked through the
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following procedures to verify functional correctness. This review focused on the availability and accessibility of refer-enced indications and controls.
(1) EP 1201.06 - Loss of Reactor Coolant and Reactor Coolant Pressure (Rev. 8, June 3, 1979).
(2) EP 1202.14 - Loss of Reactor Coolant Flow - RCP Trip (Rev.
4, June 3, 1979).
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(3) EP 1202.26 - Loss of Steam Generator Feed (Rev. 7, June 3, 1979).
(4) SP 1106.06 - Auxiliary Feedwater System (Rev. 7, June 3, 1979).
e.
AFW Pumps Endurance Test During the i.. rval of June 23-26, 1979 both AFW pumps were operated for /2 consecutive hours, as per request of NRC, to determine their endurance. After the completion of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> interval both pumps were shutdown, allowed to cool for I hour and restarted again. The test was successfully completed on June 27, 1979. No problems were identified with the performance of the pumps.
f.
Operator Guidance to Monitor Critical Parameters Special Order No. 20 (June 6, 1979) was recently prepared by the licensee to provide additional guidance for checking critical parameters for emergency procedures. The inspectors reviewed this document and noted that it included guidelines for deter-mining the status of RCS subcooling and flow, feedwater flow, and steam generator level.
In addition, it was noted that the licensee had taped subcooling curves to the operator's console for ready reference.
g.
AFW Level Control Mode Switch Modification The licensee installed a mechanical stop on switches HIS 520B and HIS 521B to prohibit the use of the Integrated Control System (ICS) control position. This modification assures the separability of the "ICS control" position of the mode selector switches from the safety grade modes of " Auto-essential" and
" Manual." The licensee has revised SP 1106.06 (" Auxiliary Feedwater System"), which describes procedures for AFW system operation. This procedure specifically prohibits the use of the ICS control position on the mode selector switches.
Pro-cedural steps for placing the AFW system in service for plant startup require the operator to place the AFW mode selector on
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auto-essential position. Other plant procedures that made reference to the ICS control mode of AFW have been revised by the licensee to preclude that mode of control. A permanent caution tag has been installed above the AFW level control switches to caution the operators not to use ICS mode of level control.
Th-inspectors have reviewed the revised procedures and have audited the control room operators and concluded that the revisions to the procedures are adequate and that control room operators are aware that ICS control of AFW is prohibited.
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h.
Incore Thermocouples Temperature Readout Range The licensee expanded the computer readout of all incore thermo-couples to a range of 0-2300 F.
The inspector reviewed the calibration and data sheets for this modification to verify its completion before the unit proceeded to Hot Standby (Mode 3).
i.
Installation of Physical Barriers in Front of Local-Remote Valve Switch Pauels The licensee installed physical barriers in front of selected local-remote valve switch panels to prevent inadvertent actuation of switches located in high traffic areas. The inspector verified the installation of these barriers for cabinets CDE 12A2 and CDYE2.
No items of noncompliance or deviations were identified.
5.
Control of Combustibles On July 7, 1979 the inspector observed about 6 gallon cans of flam-mable liquid, paper coveralls, wood and other flammable items were being stored in High Voltage Switchgear Room B.
This room contains breakers which supply safety related equipment (DH pumps, HPI pumps, SW pumps, etc.).
Station Procedure AD 1810.01.1 " Control of Combustibles" states in Section 3.1.1 that combustible material shall not be stored in areas containing safety related equipment."
The above appears to be in noncompliance with Technical Specifi-cation requirement 6.8.1 to implement approved procedures.
No additional items of noncompliance or deviations were identified.
6.
Plant Tour The inspector walked through various areas of the plant to observe operations and activities in progress, to inspect the general state
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of cleanliness, housekeeping, and adherence to fire protection rules, and to review with operators the status of various annunciators which were indicated in the control room.
No items of noncompliance or deviations were identified.
7.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of
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noncompliance or deviations.
An unresolved item discussed during this inspection is discussed in Paragraph 2.
8.
Exit Interview The inspectors met with the licensee representatives during the course of the inspection to discuss their findings and to resolve outstanding items as discussed in the report.
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