IR 05000269/1994036
| ML16242A138 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 12/21/1994 |
| From: | Harmon P, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A740 | List: |
| References | |
| 50-269-94-36, 50-270-94-36, 50-287-94-36, NUDOCS 9412290353 | |
| Download: ML16242A138 (14) | |
Text
SREGt4 UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900 ATLANTA, GEORGIA 30323-0199 Report Nos.:
50-269/94-36, 50-270/94-36 and 50-287/94-36 Licensee:
Duke Power Company 422 South Church Street Charlotte, NC 28242-0001 Docket Nos.:
50-269, 50-270 and 50-287 License Nos.:
DPR-38, DPR-47 and DPR-55 Facility Name:
Oconee Units 1, 2 and 3 Inspection Conduct October 30 - Nov mb
, 1994 Inspectors:
/
enior Resi Ins ctor Date Signed W. K. Poertner, Resident Inspector L. A. Keller, Resident Inspector P. G. Humphrey, esident Inspector
~
Approved by:
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M. V. Sinkule, Chief, Da e Signed Reactor Projects Branch 3 SUMMARY Scope:
This routine, resident inspection was conducted in the areas of plant operations, maintenance and surveillance testing, onsite engineering, and plant suppor Results:
One Violation was identified involving failure to follow procedures and the resultant misalignment of seal supply filter valves, paragraph An Unresolved Item was identified regarding the licensee's capability to man and activate the Standby Shutdown Facility, paragraph The Unit 2 refueling outage completed during this inspection period was considered well managed in the areas of minimizing personnel radiation dosage, outage cleanup and housekeepin Several instances of inadequate configuration control occurre These included:
mispositioned valves on the seal supply filter, paragraph 2.f; reversed orifices on the hydraulic operators for two main steam stop valves, paragraph 3.a.(1); and Reactor Coolant System hot leg vent valves installed backward, paragraph 3.b.(4).
Each of these instances involved a lack of attention to detai PDR ADOCK 05000269 G
REPORT DETAILS Persons Contacted Licensee Employees
- E. Burchfield, Regulatory Compliance Manager
- D. Coyle, Systems Engineering Manager
- Davis, Engineering Manager T. Coutu, Operations Support Manager
- W. Foster, Safety Assurance Manager J. Hampton, Vice President, Oconee Site
- D. Nix, Regulatory Compliance
- B. Peele, Station Manager
- G. Rothenberger, Operations Superintendent
- J. Smith, Regulatory Compliance
- R. Sweigart, Work Control Superintendent Other licensee employees contacted included technicians, operators, mechanics, security force members, and staff engineer *Attended exit intervie.
Plant Operations (71707) General The inspectors reviewed plant operations throughout the reporting period to verify conformance with regulatory requirements, Technical Specifications (TS), and administrative control Control room logs, shift turnover records, temporary modification log, and equipment removal and restoration records were reviewed routinely. Discussions were conducted with plant operations, maintenance, chemistry, health physics, instrument & electrical (I&E), and engineering personne Activities within the control rooms were monitored on an almost daily basi Inspections were conducted on day and night shifts, during weekdays and on weekend Inspectors attended some shift changes to evaluate shift turnover performance. Actions observed were conducted as required by the licensee's Administrative Procedures. The complement of licensed personnel on each shift inspected met or exceeded the requirements of TS. Operators were responsive to plant annunciator alarms and were cognizant of plant condition Plant tours were taken throughout the reporting period on a routine basis. During the plant tours, ongoing activities, housekeeping, security, equipment status, and radiation control practices were observe *
2 Plant Status Unit 1 operated at full power the entire reporting perio Unit 2 completed a refueling outage, End Of Cycle #14 (U2EOC14),
on November 19, 1994, and conducted power operations throughout the remainder of the reporting perio Unit 3 operated at full power the entire reporting perio Standby Shutdown Facility (SSF) Activation Time During the inspection period the inspectors reviewed the results of drills conducted by the licensee designed to train operators to man and activate the SSF. As a result of that review, the inspectors raised questions regarding the capability to man and activate the SSF within the allowable time fram The SSF is designed as a standby system for use under extreme emergency conditions. The SSF is provided as an alternate means to achieve and maintain hot shutdown conditions for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> on all three units following postulated fire, sabotage, or flooding events. Loss of all other station power is assumed for each event. Additionally, the licensee has taken credit for the SSF to meet the requirements of the Station Blackout Rul The SSF is designed in part to:
(1) maintain a minimum water level above the reactor core, with an intact reactor coolant system (RCS), by maintaining reactor coolant pump seal cooling; and (2)
assure natural circulation and core cooling by maintaining sufficient secondary side cooling water. RCS inventory and seal cooling is provided by the SSF reactor coolant makeup (RCM) pumps (one per unit).
Core cooling is provided by the SSF auxiliary service water (ASW) pump which supplies lake water to the affected unit(s) steam generators. Power for these pumps is provided by the SSF diesel generator. The SSF is normally unmanned and requires manual activation by operations personne SSF activation includes starting the diesel generator, SSF ASW pump, RCM pump(s), and manipulating various breakers and valves to establish flow path The licensee has determined that the SSF must be activated within 10 minutes of the onset of an event requiring SSF activation in order to prevent reactor coolant pump (RCP) seal damage/failur RCP seal failure creates a loss of coolant accident (LOCA) for which the SSF is not designed to mitigate. Therefore, as part of the SSF Emergency Operating Procedure (AP/O/A/1700/25), SSF makeup flow to the RCP seals and ASW flow to the steam generators are required to be established within 10 minute On July 27, 1994, the licensee performed a drill that was written with the intent of showing how plant personnel and equipment were
prepared to cope with mitigation of an Appendix "R" type even The drill scenario included a requirement to activate the SS The SSF activation time for this drill was approximately 28 minutes. During this drill, it took approximately 8 minutes for the personnel to acknowledge the need to activate the SSF and 20 additional minutes before the SSF was in service. A Problem Investigation Process (PIP) report (0-094-1041) was initiated to evaluate the failure to meet the 10 minute activation requiremen This PIP was classified by the licensee as a Less Significant Event (LSE) versus a more significant (MSE) which is automatically investigated for root cause determination. The screening remarks of this PIP read as follows:
"This PIP is classified as an LS Since this was a drill, several factors could have slowed the SSF activation tim Had it been a real emergency, activation time would have been decreased. However, this drill pointed out needed improvements to decrease response time and increase awareness for SSF activation. If further training and enhancements to procedures do not decrease activation time of the SSF to within 10 minutes, this PIP should be upgraded to an MSE".
During this inspection period, the inspectors requested the results of all unannounced drills related to activating the SSF within 10 minutes. The licensee informed the inspectors that there was no documentation for any drills/demonstrations related to activating the SSF within 10 minutes, prior to the July 27, 1994 dril Subsequent to the July 27, 1994 drill, there have been four documented unannounced drill All four drills were unsatisfactory in terms of meeting the 10 minute time requirement for activation of the SSF (times varied from 11 to 13 minutes).
The inspectors noted that these activation times were not conservative due to the failure to include the time required for valve stroking (valves were not actually stroked during-the drills, rather the valves were assumed to go instantly open or closed).
The inspectors concluded that valve stroke times would add at least one minute to any activation time involving a single unit scenario and probably more than one minute for a multi-unit scenari Given the consistent failure to meet the 10 minute activation criteria, the inspectors questioned whether the SSF could meet its design basis requirements and why the PIP was not upgraded to an MSE category. In response, the licensee informed the inspectors that management was unaware that any drills subsequent to July 27, 1994, indicated unacceptable results. As of the end of the inspection report period, the licensee was still evaluating the conduct of these drills and the implications on SSF operabilit The inspectors concluded that unless the licensee could consistently demonstrate that the SSF could be activated within 10 minutes, or sufficient margin existed to extend the activation
- 4 time, the SSF would not be able to meet its design basis requirements. Additionally, any drill designed to verify that the SSF could be activated within the required time should include valve stroke times and other factors in order to be bounding and conservative. In addition to the operability concerns, the inspectors were concerned that the drill deficiencies were not flagged for licensee management attentio Pending the licensee's evaluation of these issues, this matter is identified as Unresolved Item 50-269,270,287/94-36-01:
Failure To Meet SSF Activation Time Requiremen Keowee Main Stepup Transformer Fan Failure At approximately 10:14 a.m., on November 14, 1994, a Keowee main step-up transformer oil flow failure alarm was received in the Keowee control room and the Oconee Unit 1 and 2 control roo Based on this alarm condition the Keowee overhead emergency power path was declared inoperable and the requirements of TS 3.7.2 were implemented. TS 3.7.2 requires that the alternate power path be verified operable within one hour and every eight hours thereafte The licensee determined that the cause of the alarm was a burned/failed relay coil for fan banks 1-The failed coil resulted in a blown fuse and loss of power to the relays for fan banks 1-The relay was repaired and the Keowee overhead path was declared operable. The inspectors monitored activities in the Oconee control room and at the Keowee Hydro Station during the troubleshooting activities to determine the cause of the failur The operators' actions were conservative and conducted in a methodical manne Unit 2 Outage Summary On November 17, 1994, Unit 2 was brought up to 15 percent power to warm the main turbine generator prior to testing its overspeed control After successfully completing the main turbine/
generator trip test, reactor power was reduced to approximately 0.1 percent for a modification of pressurizer level instrument root valve 2RC-IV0165. The modification consisted of fabricating and mechanically installing a bonnet to enclose the existing valve bonnet which was leaking. This modification was performed in lieu of replacing the valve which would have involved shutting the unit down and depressurizing the RC On November 19, 1994, the subject valve modification was complete Power escalation began at 12:34 p.m., and the main turbine/generator was placed on line at about 15 percent reactor power leve However, after 45 seconds the turbine/generator tripped off-line due to an incorrectly adjusted thrust wear detector. The discrepancy was corrected and the turbine/generator was again placed in operation at 5:00 During subsequent power escalation, a discrepancy was noted in that the delta flux (upper core power minus lower core power)
provided by power range instrument NI-8 was responding opposite to the delta flux provided by the other power range instruments (NI 5, NI-6, and NI-7).
Accordingly, the licensee reversed (opposite to that shown on the drawing) the leads in the cabinet associated with NI-8. The indication from NI-8 then paralleled those of the other power range instruments. This occurred at approximately 72 percent power leve The licensee performed a continuity check of the NI-8 leads and determined that leads must have been crossed at the detector during some previous maintenance activity. During refueling outage U2EOC14, maintenance activities on the associated reactor building penetration returned the leads to the applicable drawing configuration; thereby reintroducing the previous erro The leads were subsequently changed back to their correct configuration at the cabinet and crossed at the inside.containment penetration to correct the indication. The licensee has indicated that a Licensee Event Report will be issue A Precision Heat Balance was performed which revealed a power level of 1.4 percent greater at the 100 percent power level than that indicated on the Operator Aid Computer (OAC).
As a result, a conservative measure was taken to limit the indicated power level on the OAC to 98.5 percent until the differences were resolve The licensee subsequently determined the AC to be more accurate than the Precision Heat Balance and power was increased to 100 percent as indicated by the 0A The "As Low As Reasonably Achievable (ALARA)" principal was stressed throughout the entire outage period and the results were commendable. Radiological areas were cleaned and dose rates were reduced significantly. As a result, the actual man-rem was lower than the projected (134 REM target vs 112 REM actual) and the total cubic feet of disposable radiological waste was less than that projected (10,494 cu. ft. target vs. 7,435 cu. ft. actual). High Pressure Injection (HPI) Filter On November 18, 1994, the Unit 2, 2A seal supply filter was placed in service with the vent and drain valves open and RCS at full temperature and pressure. This resulted in reducing approximately 1500 gallons of RCS inventory out of the letdown storage tank and additional inventory from the borated water storage tank (BWST).
The vents and drains were piped to the high activity waste tan Seal injection flow was lost to the reactor coolant pumps (RCPs)
and the seal return line from the 2Al RCP isolated. The 2A1 pump had been previously shut down as a result of high vibratio The remaining 3 RCPs were operating with the unit at 10 percent power after completing the refueling outage. In addition, the 2B HPI
- pump automatically started because of the low seal injection flo Because of the rapid drop in letdown storage tank inventory, the
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control room operators aligned the HPI pump suction to the borated water storage tank to prevent loss of net positive suction and possible damage to the pump Additional immediate operator actions included manually closing the vent and drain valves located in the auxiliary buildin The 2A seal supply filter had been out of service for a gasket replacement. The requirements for returning it to service were specified in Enclosure 6.7, Swapping Seal Supply Filters, of operations procedure, OP/2/A/1104/02, High Pressure Injection System. Step 2.5 requires a leak check prior to restoring the filter to service. The leak check includes closing the vent and drain valves. Contrary to the procedural requirements, these valves were not closed and resulted in the events described abov This is identified as a Violation 50-270/94-36-02:
Failure to Follow HPI Restoration Procedur Problem Investigation Process (PIP) #2-094-1667 was issued, but described the event as a failure to close the vent and drain valves prior to placing the filter in service. There was no discussion of the loss of inventory or the operator actions in response to this event. The PIP was screened and determined to be a Less Significant Event (LSE).
An event classified as a LSE is not automatically investigated for a root cause determinatio After the inspectors questioned the classification, the licensee revised the PIP to more accurately reflect the events that occurred and changed the classification to a More Significant Event (MSE).
Within the areas reviewed, one violation was identifie.
Maintenance and Surveillance Testing (62703 and 61726) Maintenance activities were observed and/or reviewed during the reporting period to verify that work was performed by qualified personnel and that approved procedures adequately described work that was not within the skill of the craft. Activities, procedures and work orders (WO) were examined to verify that proper authorization and clearance to begin work was given, cleanliness was maintained, exposure was controlled, equipment was properly returned to service, and limiting conditions for operation were me The following maintenance activities were observed or reviewed in whole or in part:
(1) Investigate/Repair Slow Stroke Time for Main Steam Stop Valves, Work Order Task (WOT) 94062775-05 The Main Steam Stop Valves (MSSVs) are the main steam isolation devices at Oconee. These valves (4 per unit),
have a Channel A and B instrument string which actuate a
respective solenoid upon receipt of signal, which close the valves when required (i.e., immediately following a reactor trip).
TS 4.8 requires that the operation of each of the MSSVs be tested during each refueling outage to demonstrate a closure time of one second or less for Channel A and a closure time of 15 seconds or less for Channel B. During testing of the Unit 2 MSSVs on November 16, 1994, MSSVs 3 and 4 (Channel B) required 20 seconds to clos The inspector observed the troubleshooting efforts conducted to determine the cause of the slow stroke time These troubleshooting efforts were considered to be appropriate, identifying the cause to be swapped supply and drain orifices which mount inside ports of the test solenoid associated with each valve. The orifice designed to go into the supply side port is smaller in diameter and therefore restricted drain line flow and slowed the closure tim The orifices were swapped back and the subsequent stroke tests were satisfactory. The test solenoids had been replaced during the outage and the orifices were inadvertently swapped during the installation proces (2) Replacement of Automatic Recirculating Control (ARC) Valves, NSM22926 The Unit 2 ARC valves in the discharge side of the 2A and 2B motor driven emergency feedwater pumps were replaced during the refueling outage (U2EOC14).
The replacement was deemed necessary because of past incidents where the emergency feedwater system pressure had exceeded piping design pressure and from inadequate operation of the original valves to bypass flow and maintain desired flow rates without overpressurization. Unlike the original valves which operated in full open or full closed positions only, the new valves have the capability of modulating bypass flow to the Upper Surge Tank while maintaining proper feedwater flows as desire The inspector reviewed the work activity in progress and reviewed the completed documentation. The activity was determined to have been satisfactorily complete (3) Feedwater System, Feedwater Pump Suction and Discharge Pressure Switch Calibration (Outage), IP/O/B/0273/005B-1 On November 7, 1994, the inspector reviewed activities in progress during the calibration of Unit 2 feedwater pressure switch 2PS248. The work was authorized per WOT 94066986-01 and documentation was completed for the steps that had been performe The work activity was properly authorized and test instruments utilized had been calibrated within the allowable time period. The activity was determined to meet acceptable standard (4) Steam Generator Temperature Compensated Operating Level Instrumentation Calibration, IP/0/A/0275/005Q The inspector reviewed activities in progress during calibration of the 2A steam generator temperature compensating level contro The effort was authorized by WOT 94067881-01, SG Temp Comp Operating Level Calibratio The purpose was to provide precise monitoring of steam generator level temperature, as well as ensure proper operation and indication of the functional area The work was performed to the applicable procedure and was determined to meet acceptable standard (5) Perform Operator Check-out Overspeed Test, 2A-FWPT, MP/0-O/B/1320/002 The inspector witnessed activities in progress during the overspeed trip testing of the 2A main feed water pump turbine. The event occurred on November 9, 1994, and was performed in accordance with procedure MP/0-O/B/1320/00 The activity was authorized per WOT 94064453-0 The effort was performed to acceptable standards and the results were within the acceptable tolerance Surveillance activities were conducted with approved procedures and in accordance with site directives. The inspectors reviewed surveillance performance, as well as system alignments and restorations. The inspector assessed the licensee's disposition of discrepancies which were identified during the surveillanc The following surveillance activities were observed or reviewed in whole or in part:
(1) IP/0/A/3000/003, 125 Vdc Instrument & Control Battery Service Test and Annual Surveillance This surveillance demonstrated that the control batteries were capable of delivering the power required during a loss of coolant accident (LOCA) for a period of one hour, and satisfied the requirements of TS 4.6.10. The inspector observed portions of the test for the 3CA battery and reviewed the results of the tes All activities observed were satisfactory and all measured parameters were within required limit (2) PT/O/A/0300/01, Control Rod Drive Rod Drop Time Test On November 15, 1994, the inspectors witnessed control rod drop time testing on Unit 2. The test was performed immediately prior to restart near the completion of refueling outage U2EOC14. The purpose of the test was to functionally check the control rod drive system total trip time from the manual trip button (or the auxiliary power supply trip switch) to three-fourths insertion of each control rod into the core from the fully withdrawn positio The acceptance criteria was that the drop time did not exceed 1.66 seconds with reactor coolant flow at full flow conditions. The inspectors verified that all control rod drop times were well within the acceptance criteri (3) PT/2/A/0150/15D, Intersystem LOCA Leak Test On November 15, 1994, the inspectors witnessed portions of the Intersystem LOCA Leak Test for Unit 2. This test measured backflow through various Core Flood and LPI check valves. All activities observed were satisfactory and all acceptance criteria were me (4) Reactor Vessel Head and High Point Vent, PT/2/A/201/05 The performance of PT/2/A/201/05, Enclosure 13.2, Testing of
'B' Hot Leg Vents, was reviewed by the inspector. The activity verified the venting capabilities of valves 2RC157 and 2RC158 on the reactor coolant system. Both valves had previously been reworked and were reinstalled in the reverse directio This condition was discovered during leak testing, when the valves failed to seat against RCS pressur The valves were again cut out and installed in the correct orientation. However, 2RC157 failed to pass flow when tested and was reworked again. The valves were again tested on November 14, 1994, and were verified to operate properl Although the valves were installed incorrectly, the performed testing identified the discrepancy and corrective actions were implemente (5) High Pressure Injection (HPI) Full Flow Test, PT/2/A/251/24 The inspector reviewed activities in progress during testing of the Unit 2 HPI pump The test method established flow through the "A" and "B" trains of the low pressure injection system and the A and B trains of HPI to the RCS to verify proper operation of the check valves in each flowpat Additionally, the HPI check valves from the borated water storage tank (BWST) and the valves at the discharge of each
of the 3 HPI pumps were evaluated as part of the performance test. The activity included the suction check valves from the BWST and the letdown storage tank (LDST) which were tested in the reverse directio The HPI pumps (2A, 2B, and 2C) were tested at the beginning of refuel outage U2EOC14. At that time, the B pump performed at less than the required flow and pressure when compared to its performance curve. As a result, the 2B pump was replaced during the outage with a rebuilt pump. After the replacement, the HPI pumps were again tested and results indicated that both the B and C pumps had performed at lower than acceptable levels. Further investigation revealed that the wrong data had been documented for the C pump. After the corrected data was evaluated, the C pump performance was found to be acceptabl At a flow rate of 475 gpm, the re-built 2B pump developed a 1083 psig discharge pressure head which was approximately 15 psig above the pressure developed by the pump.that was replaced. The previous pump had an acceptance range required of greater than 1145 psig and a required action when the head developed became less than 1109 psig. The inspectors attended the Plant Operating Review Committee meeting on November 10, 1994, which reviewed the data and determined that the performance data developed from the re-built 2B pump would meet the plant design requirements and that the baseline performance curve for this pump would be lower than for the replaced pump. Therefore, the 2B pump was found to be acceptabl (6) Reactor Coolant Leakage, PT/1/A/600/10 On November 24, 1994, the inspectors reviewed this Unit 1 surveillance activity. This procedure implements the requirement of TS 4.1.2 to evaluate system leakag All acceptance criteria were met and no discrepancies were note (7) Periodic Instrument Surveillance, PT/1/A/600/01 On November 23, 1994, the inspectors reviewed this Unit 1 surveillance activity. This procedure monitored control room instrumentation for operability. All acceptance criteria were met and no discrepancies note No violations or deviations were identifie.
Onsite Engineering (37551)
During the inspection period, the inspectors assessed the effectiveness of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other areas involving the Engineering Departmen Minor Modification OE-6989, Leak Seal Valve 2RCVI-165 The inspectors reviewed the 10 CFR 50.59 evaluation and modification package associated with this minor modification. The subject Unit 2 valve (2RCV-165) is a Kerotest globe valve and is the upper root valve for pressurizer level transmitter 2RC LT0004P3. The purpose of the modification was to stop a body to bonnet steam leak. The modification installed a seal cap and retention device to allow injection of sealant to stop the body to bonnet leak. No discrepancies were note b. Reactor Building Cooling Unit Replacement, NSM-22963 The three Reactor Building Cooling Units (RBCU) were replaced in Unit 2 with new coolers during refueling outage U2EOC14. The changeout of the 2A, 2B, and 2C coolers was necessary because of cooling water leaks that had reached approximately 2.5 gp The inspectors reviewed efforts in progress during the changeout and reviewed the completed documentatio The work was performed to the requirements specified in Section XI, of the ASME Code, Winter 1980 Edition. A PIP was generated during the hydrostatic testing based on valve manipulation that was not conducted according to the test procedure. However, an evaluation was performed and the results of the test were determined to be acceptabl The cooler replacement and the completed documentation was reviewed during the inspection period by the inspector The overall effort was determined to be acceptabl Replacement of the Essential Control Power System Inverters, NSM ON2-2881 The Unit 2 240/120VAC essential control power system static inverters (2KI, 2KU, and 2KX) were replaced during the U2EOC14 outage. The replacement of the inverters and associated equipment was necessary because of their age of approximately 20 years and decreasing reliability. In addition, parts were becoming difficult to obtai The licensee determined the inverters to be nonsafety-relate However, the DC supply breakers for the inverters which were also replaced under the modification, were safety-related because they were located within a safety-related distribution center and were required to trip to provide adequate power coordinatio While performing the functional test on the replacement 2KU inverter, a procedure error resulted in a blown fuse. The fuse
was replaced, the test procedure corrected, and the test was resumed. A second test error resulted in another blown fuse and damage to the inverter transformer. The licensee generated PIP
- 2-094-1628 to document and identify corrective action Although problems were experienced and corrected during the testing of the new inverters, the work was completed prior to Unit 2 restart and the finished product was acceptable. The inspectors reviewed the work while in progress and the completed documentatio No violations or deviations were identifie.
Plant Support (71750)
The inspectors assessed selected activities of licensee programs to ensure conformance with facility policies and regulatory requirement During the inspection period, the following areas were reviewed:
radiological controls; radiological effluent, waste treatment, and environmental monitoring; physical security; and fire protectio The inspectors toured the Unit 2 Reactor Building following the completion of all outage-related work and building cleanup. The building was very clean, and material condition was very good. The emergency recirculation sump was clean and free of any potential blocking materia No violations or deviations were identifie.
Inspection of Open Items (92901)
The following open item was reviewed using licensee reports, inspection record review, and discussions with licensee personnel, as appropriate:
(Closed) IFI 50-270/94-32-01, Failure To Detect Inadvertent Quench Tank Venting The inspectors reviewed the Unit 2 operator actions and interviewed personnel associated with the venting of the pressurizer to the quench tank while the quench tank was also aligned to the steam generator vents on October 8, 1994. This alignment provided a vent path from the pressurizer to the main condenser via the quench tank and the steam generators. The inspectors questioned the operators' actions as to why the venting was not detected when radiation indicator alarm (RIA) 40, Off-Gas Effluent, first alarmed. The inspectors reviewed documentation and held discussions with operations personnel associated with the issue. As a result, the inspectors determined that the operators had responded to the alarm and found that maintenance personnel were draining water from the RIA-40 process tubing. At that time, the operators discussed with maintenance personnel the possibility of the alarm being generated from the on-going work effort and
determined that activity in progress was the source of the alarm since the alarm had cleare The next shift began filling the steam generator with the shell side vents open to the quench tank and again the RIA-40 alarme The alarm cleared and the activity levels decreased over a period of about one hour. However, a third alarm occurred when nitrogen was vented off the pressurizer; but the nitrogen pressure in the quench tank did not increase as expected. The senior reactor operator (SRO) had the side vents on the steam generator closed and then the pressure began to increase in the quench tank as expected and the activity counts indicated by RIA-40 decrease The SRO determined that the problem had developed by having the shell side vents open on the steam generator at the same time the pressurizer vents were open to the quench tank. This had resulted from performing two procedures at the same time without a conflict statement in either. Corrective actions involved revising the applicable procedures (OP/2/A/1103/11, Draining and Nitrogen Purging of the RC System and OP/2/A/1106/08, Steam Generator Secondary Hot Soak, Fill, Drain, and Layup) to include a caution statement in each to prevent the two procedures from being implemented at the same tim Although the Offgas Radiation Monitor (RIA-40) alarmed, the main stack monitors did not alarm and the peak indicated on the stack monitor was approximately 20 percent of that required for alar Based on the actions taken by the operators and the corrective actions implemented to prevent future recurrence, this item is close.
Exit Interview The inspection scope and findings were summarized on November 30, 1994, with those persons indicated in paragraph 1 above. The inspectors described the areas inspected and discussed in detail the inspection findings addressed in the summary and listed below. The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspectio Item Number Description/Reference Paragraph 50-269,270,287/94-36-01 UNRESOLVED ITEM:
Failure To Meet SSF Activation Time Requirement (paragraph 2.c).
50-270/94-36-02 VIOLATION:
Failure to Follow HPI Restoration Procedure (paragraph 2.f).