IR 05000346/1989016
| ML20246C465 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 08/17/1989 |
| From: | Defayette R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20246C458 | List: |
| References | |
| 50-346-89-16, NUDOCS 8908240394 | |
| Download: ML20246C465 (24) | |
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A, U.S.-NUCLEAR REGULATORY COMMISSI0h
REGION III
Report No. 50-346/89016(DRP)'
~ Docket No. 50-346
- Operating License No. NPF-3 Licensee: Toledo Edison Company
. Edison Plaza 300 Madison Avenue Toledo,'OH 43652 Facility Name: Davis-Besse.1
' Inspection At:: Oak: Harbor,-Ohio Inspection Conducted: ' June 5 to July 16 and 24, 1989-In'spectors:. P. M. Byron-E. R. Schweibinz D. C. Kosloff-
.R. K. Walton
- Approved By:
DeFayet, Chief.
[7
Reactor Projects Section 3A Date
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-Inspection Summary.
Inspection on June 5 through July 16 and 24, 1989 (Report No. 50-346/89016(DRP))
Areas-Inspected: A routine unannounced safety inspection of licensee action on previously identified items,' licensee event reports,' allegations,' plant
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operations,: radiological controls, maintenance / surveillance, emergency-preparedness, security, engineering and technical support, and safety assessment /
quality verification'was performed.
Results:.0perating crews made several errors as a result of procedural problems
.and inattention to detail (Paragraph 5).
A fire protection surveillance was missed as a result of procedure and procedure process weaknesses (Paragraph ').
Two violations of the General Design Criteria due to design errors were
. identified (Paragraphs 3 and 10).
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DETAILS i
1.
Persons Contacted a.
Toledo Edison Company (TED)
D. Shelton, Vice President, Nuclear I
- G. Gibbs, Quality Assurance Director
- L. Storz, Plant Manager
- W. Johnson, Plant Maintenance Manager
- R. Flood, Plant Operations Manager E. Salowitz, Planning and Support Director S. Jain, Engineering Director G. Grime, Industrial Security Director D. Timms, Systems Engineering Supervisor
- T. Anderson, Maintenance and Outage Management Manager P. Roelant, Systems Engineering
- C. Hengge, Fire Protection Compliance Supervisor R. Schrauder, Nuclear Licensing Manager G. Skeel, Nuclear Security Operations Manager
- J. Polyak, Manager R6diological Control
- R. Collings, Quality Assurance
- A. Zarkesh, Independent Safety Engineering
- J. Gates, Manager Systems Engineering
- E. Shingleton, Licensing Engineer
- R. Gaston, Licensing Engineer
- T. Myers, Technical Services Director
- G. Honma, Compliance Supervisor
- J. Dillich, Superintendent Shift Operations
- K. Prasad, Nuclear Engineering b.
- P. Byron, Senior Resident Inspector
- D. Kosloff, Resident Inspector E. Schweibinz, Reactor Inspector R. Walton, Resident Inspector in Training
- Denotes those personnel attending the July 24, 1989, exit meeting.
2.
Licensee Action on Previous Inspection Findings (92701)
a.
(Closed) Open Item (346/85025-01(DRP)): Review of licensee's corrective action to resolve Facility Change Request (FCR) closecut backlog. The licensee has significantly reduced the FCR backlog closecut.
The licensee's corrective action program was reviewed in a previous inspection and is documented in Inspection Report No. 50-346/88006. This item is closed.
(_ Closed) Open Item (346/85037-01(DRP)): Multiplexer change out for b.
plant computer. The licensee issued FCR 84-0083 to implement the replacement of the multiplexer. The first multiplexer was replaced
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during the last refueling outage. The remaining units will be replaced one per refueling outage and will be completed during the eighth refueling outage. This item is closed based on the installation of the first unit and the schedule for installing the remaining units.
c.
(Closed) Violation (346/85037-07(DRP)): Procurement, receipt a'nd installation of incorrect pyrometer in an emergency diesel generator (EDG). The licensee ir, stalled a pyrometer with the same style number but a different resistance in an EDG. The different pyrometer did not affect the temperature readings. The implementation of the configuration management program corrected the programmatic deficiencies which caused the violation. This item is closed.
d.
(Closed) Open Jtem (346/86005-ll(DRP)): Establishment of management controls to assure appropriate closeodt of Course of Action, SALP IV, Performance Enhancement Program (PEP) and Interim PEP commitments.
The licensee placed the above commitments on its Licensing Connitment Tracking System (LCTS). This item is closed.
e.
(Closed) Open Item (346/86009-01(DRP)):
Verification of supervisory review of the fuel handling ventilation system similar to that used in the System Review and Test Program. The open item was issued to follow the commitment. The licensee issued a report for the fuel handling area ventilation system supervisory review on February 1, 1988. Revision 1 to the report (NES-88-0189) was issued March 2, 1988.
Four solenoid valves were.added to the preventive maintenance program on May 24, 1989, as a result of the review. The inspectors reviewed both reports. The licensee met its commitment and this item is closed.
f.
(Closed) Violation (346/86012-03(DRP)): Failure to submit a Licensee Event Report (LER) within 30 days of discovery. The licensee denied the violation.
The licensee contended that "the clock" started at the deportability date rather than the discovery date as described in NUREG 1022, Supplement 1.
The remedial action was to isolate the water lines to prevent damage and an LER was issued.
In addition, the licensee has improved its program for deportability. The inspectors consider the licensee's actions adequate and this item is closed.
g.
(Closed) Violation (346/86032-09(DRP)): The number of operable instrument strings for containment radiation-high was less than the minimum number required. This event is also described in LER 86032. The violation is closed and the event corrective
actions will be tracked by LER 86032.
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(Closed) Open Item (346/86032-14(DRP)):
Install a continuous nitrogen supply system to alleviate leakage. This was to be implemented by FCR 84-104 which was completed in December 1988. The inspectors
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reviewed licensee documentation, operating procedures and system j
installation.
This item is closed.
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(Closed) Unresolved Item (346/87004-01(DRP)): Review root cause of improperly positioned damper in control room emergency ventilation system (CREVS). The inspectors observed an: improperly positioned p
CREVS damper during a system walk down. The licensee determined L
that the root cause of the condition:was an inadequate locking device.
-The licensee replaced the short bolt and wing nut with a longer bolt, lock washer, and nut. This was implemented by FCR 87-0087. The inspectors reviewed the completed installation. The corrective h
action appears to be adequate in that the discrepancy has not been identified subsequently. This item is closed.
(Closed) 0)en Item (346/68002-Ol(DRP)):.The licensee had begun
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Facility C1ange Request (FCR) 66-0066 to help ensure the proper
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electrical fuses are available when needed to restore operability of equipment. The inspectors reviewed a draft copy of Drawing E2014
" Fuse Database" and discussed the progress of the FCR. The drawing, the licensee's progress to date and the licensee's current schedule for completion are satisfactory. This item is closed.
3.
Licensee Event Reports Followup (92700)
Through direct observations, discussions with licensee personnel, and review of records, the following licensee event. reports were reviewed to determine that deportability requirements were fulfilled, that immediate corrective action was accomplished, and corrective action to prevent-recurrence was accomplished in accordance with Technical Specifications (TSs). The LERs listed below are considered closed, a.
(Closed) LER 83-029: Main Steam Safety Valves (MSSV)-setpoints found out of tolerance low. Reviewed in Inspection Report No. 50-346/84020.
Improper opening and closing of the MSSV's
~is also addressed in NRC Safety Evaluation Report (NUREG-1177)
regarding the Davis-Besse loss of feedwater transient of June 9, 1985.
The licensee continues to evaluate MSSV operating anomalies in an ongoing program, b.
(Closed) LER 83-030: Floor plugs were removed that were part of the negative pressure boundary and fire barriers. The corrective actions included appropriate marking of the floor plugs and revision
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of procedure. The inspectors have observed that floor plugs are i
identified as negative pressure boundaries and as fire barriers.
c.
(Closed) LER 83-044: Four valves failed the Containment Local Leak Rate test.
Three valves failed due to component failure and the fourth due to a Limitorque operator set point procedure deficiency.
All valves were repaired and the procedure was revised.
I d.
(Closed) LER 83-063: Criteria for separation between two fire areas not being met. Reviewed in Inspection Report No. 50-346/84028. The LER was revised to include the determination of the long term corrective actions and the Fire Hazards Analysis Report (FHAR)
was revised to address the subject pipe hoses.
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(Closed) LER 83-069: Fire doors had non-UL listed hardware attached.
Reviewed in Inspection Report No. 50-346/860G6. The licensee completed the evaluation by Underwriters Laboratories, Inc. (UL)
and implemented the corrective actions.
f.
~(Closed) LER 84-015:
Velan c bck valves had potential for binding due to design of the antirotational stops. The licensee also submitted a 10 CFR 21 report on this subject. Valves were subsequently modified to eliminate the binding concern.
g.
(Closed)'LER 84-020:
Inoperable fire dampers. Review in Inspection
- Report No. 50-346/85003 resulted in an unresolved item (346/85003-07)
which was pending a review of the licensee's response ~to a previous item of noncompliance. issued in. Inspection Report No. 50-346/84028.
This unresolved item was closed in Inspection Report No.'50-346/85025.
No further questions remain and this LER is closed.
h.
(Closed)LLER 85-002:. Reactor trip during zero power physics testing.
During this trip, the No. 1 auxiliary feea pump had. suction transfer problems that have been subsequently resolved. This LER is closed.
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(Closed) LER 86-005:
Improper boot seal installation. The licensee revised this.LER.to provide additional.information. The inspectors'
observations of installations to the revised procedures has indicated the initial problems have been resolved. This LER is closed.
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(Clos:.Ji LEn 86-03?: The number of operable instrument strings for containmen H i31ation-high was less than the minimum nu::h e required. The licensee's corrective action was to counsel the individuals and revise the conduct of maintenance and' conduct of operations precedures to better coordinate the work activities to be performed. The inspectors reviewed the revised procedures.
In addition, the licensee emphasizes the need for increased attention to detail at supervisor's meetings. 'The licensee has completed its-corrective actions and they appear to be effective. This item is closed.
k.
(Closed) LER 87-010:
In August 1987, a lightning strike on the power grid initiated vibrations on the turbine generator causing a turbine trip and reactor trip. The ensuing steam plant transient revealed deficiencies in the licensee's steam plant automatic response, including a failure of the moisture separator reheater (HSR) second stage source valve to close resulting in a faster than normal reactor coolant system (RCS) cooldown rate and secondly, a sluggish response from the Rapid Feedwater Reduction (RFR) circuitry. The licensee performed the following items to ensure a more reliable automatic plant response:
(1) The turbine generator vibration trip set point was increased as recommended by the vendor.
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A' change was made to the MSR operating procedure to include manual operation of the MSR steam control system.
.(3) The' time constant for the RFR circuitry was reduced from
.9.0 seconds to 1.5 seconds.
.(4) The licensee has reviewed the previous-five plant trips to determine if other' defective steam plant equipment had caused excessive RCS cooldowns. No common root cause was noted.
(5) Defective MSR pressure switch PS9806 was replaced and a
. preventive maintenance (PM) activity was implemented to periodically calibrate both_PS9806 and PS9807. The inspectors have reviewed licensee paper work and will continue to monitor licensee maintenance and PM to PS9806-and PS9807. This item is closed.
1.
(Closed) LER 88-008: ' Nuclear Safety-Related equipment potentially impacted by non-seismic equipment. Cabinets C4601 and C5751 were originally designed to be non-seismic, however, subsequent facility
. modifications had huclear Safety Related (NSR) equipment installed in the vicinity of these panels. The potential for these panels to impact NSR equipment was over looked during hazard analysis review.
The licensee committed to:
(1) Seismically restrain C4601.
(2) Move NSR equipment out of falling arc distance of C5751.
(3) Perform a walkdown of non-seismic free standing electrical panels.-
(4) Retrain personnel involved in hazards analysis review.
The walkdown of 132 non-seismic, free standing, electrical panels and cabinets revealed that 72 cabinets were within the falling arc distance of NSR equipment. The licensee determined that no rework of cabinets would be necessary based on calculations. The inspectors have reviewed. licensee documents and calculations and have inspected Cabinets C4601 and C5751. This item is closed, m.
(Closed) LER 89-004: Potential for Circulating Water Line Break 10 cause Loss of Service Water (SW) Pumps. This LER described how water from a circulating water line break could flow from the condenser pit through the SW Tunnel to the SW Pump Room.
In the past such an event was not considered credible because an opening in the wall between the condenser pit and the SW Tunnel had not been considered (USAR Section 3.6.2.7.2.13) and because, if SW Tunnel flooding were to occur, it was )ostulated that operator action would isolate the SW Pump Room from tae SW Tunnel (USAR Section 9.2.1.2).
On February 6, 1969, the inspectors informed the licensee that, contrary to USAR Section 3.6.2.7.2.13, there was a hole in the wall between the condenser pit and the SW Tunnel and that, contrary to USAR Section 9.2.1.2, there was no procedural guidance for operators
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4-p to isolate the'SW Tunnel from the SW Pump Room in.the event of flooding in the SW Tunnel. The inspectors also informed the licensee L
that the combination of the two conditions meant that the SW Pumps
. ere not protected from flooding caused by a circulating water line w
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break. This is~a-violation (50-346/89016-01(DRP)) of 10 CFR 50, Appendix A, " General Design Criteria for Nuclear Power Plant" which requires that components important to safety be protected from the effects of discharging fluids which may result from equipment failures. _This violation first occurred on April 22, 1977, when
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i the licensee received its license. On February 7, 1989, the licensee documented the condition with two. Potential Condition Adverse to Quality Reports. On February 10, 1989, the licensee issued Standing
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Order No.89-026, " Service Water Pump Flooding Protection" and
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installed flood prevention equipment in the SW Pump Room. The Standing Order described the potential for Circulating Water to flood the SW Pumps and provided the operators with written guidance on protecting the SW Pumps from flooding. The licensee issued LER 89-004 on May 10, 1989, but the date of discovery of the' event was February 7, 1989. 'This is a violation (50-346/89016-02(DRP))-
of 10 CFR 50.73 (a) which requires that LERs be submitted within 30 days of discovery of an event. The inspectors identified numerous errors in the LER and the analysis of the event was inadequate. The corrective action for the reporting violation should include-the submittal of a revised LER. This LER is closed.
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(Closed) LER 89-006: Leak Test of Fission Detector Not Performed Prior to InstallacTon. See Paragraph 6 for additional information.
This LER is closed.
4.
Allegations (71707)
(Closed)~ Allegation (RIII-88-A-184) Technical Specification Interpretation:
The allegation dealt with the interpretation of a time requirement of Technical Specification 4.10.2.2.
Region III requested that the licensee investigate the allegation and specifically address three areas.
a.
Perform a review of the Physics Testing that was performed after the technical specification interpretation described in the allegation.
b.
Identify and report any activities that may have resulted in the violation of Technical Specification 4.10.2.2 in the specified time frame.
c.
Describe actions taken to correct the erroneous interpretation.
The licensee's review of the physics testing revealed that no technical specification violations occurred. Physics testing commenced 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> and 58 minutes after the start of the source range functional test which was within the time specified by the technical specifications. The licensee withdrew the incorrect interpretation by memorandum (NEN 89-30014)
dated April 7, 1959, and on December 9, 1988, it voided a procedure temporary approval (TA) which incorporated the interpretation into Procedure DB-PF-03212.
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During the course of the investigation, the licensee determined that the author of the interpretation had previously done work in this arca, was familiar with the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> limitation, and had proposed that the time be increased to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as it is believed that the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> requirement is unnecessarily restrictive. A safety evaluation was written to support the proposed technical specification change and an FCR was written to accomplish this. The technical specification change request had not been submitted. Several weeks before December 4, 1988, it was proposed that the FCR be cancelled and a license action request (LAR) be issued to initiate the revision. The investigators concluded that the perception could exist that the change in position resulted from pressure. The licensee also determined during its investigation that statements were made during a discussion relating to the technical specification interpretation at a December 4, 1988, meeting which could be construed as restricting an individual's access to the NRC.
The licensee then expanded its original investigative effort by involving the security investigators and finally used outside counsel to conduct the investigation. The outside counsel concluded that there was no intent to restrict anyone's access to the NRC but that the individual who made the statement was asking if the person with the concern was satisfied with what was being provided regarding the interpretation. Outside counsel believed that the phrasing of the question could have been better. He also concluded that the individual making the interpretation did so without pressure and used his prior knowledge that the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> limitation had no sound technical basis. He recommended that both parties be counselled which has been done. The licensee has also implemented a technical specification interpretation procedure (NB-NL-00809).
The inspectors reviewed the licensee's investigation and corrective actions, the applicable nuclear instrument functional procedures and the completed low power physics test.
In addition the inspectors discussed the event with the individual who made the technical specification interpretation.
Based on this review, the inspectors conclude that the Region III questions and the additional issues were adequately addressed by the licensee. The inspectors also interviewed the individuals involved concluded that the change in position previously discussed did not result from pressure and that the other individuals access to the NRC was not restricted. This allegation is closed.
5.
Plant Operations (42700, 71710)
a.
Operational Safety Verification Inspections were routinely performed to ensure that the licensee conducts activities at the facility safely and in conformance with regulatory requirements. The inspections focused on the implementation and overall effectiveness of the licensee's control of operating activities, and on the performance of licensed and non-licensed operators and shift managers. The inspections included direct observation of activities, tours of the facility, interviews and discussions with licensee personnel, independent verification of I
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safety system' status and limiting conditions of operation (LCO), an'd-reviews of facility procedures, records, and reports.. The following items were considered during these inspections:
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' Adequacy of. plant staffing and' supervision.
Control room professionalism, including procedure
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adherence, operator attentiveness, and-response to
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alarms, events, and off-normal conditions.
Operability of_ selected safety-related systemr,_
including attendant alarms, instrumentation, and controls.
Maintenance of quality records and reports.
- The inspectors observed that control room shift supervisors, shift managers, and operators were attentive to plant. conditions, performed frequent panel walkdowns and were generally responsive to off-normal alarms and conditions.
The cperating crew was generally cognizant of ongoing work activities.=
Surveillance and testing activities were_ appropriately authorized and logged. Licensed operators were generally cognizant of entry
into and compliance with LC0 action requirements.
On June 5, 1989, at about 12:10 p.m., the licensee increased the volume of fluid in Core Flood Tank.(CFT)-1-2. Technical Specification 4.5.1.2 requires verification of boron concentration
'within six hours of a volume increase of eighty gallons or more.
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CFT l-2 was. sampled at 12:30 p.m., but the shift supervisor.did not review the sample until 9:15 p.m.
This is an unresolved item (50-346/89016-03(DRP)) pending the inspectors further. review.
On June 9, 1989, at about 7:20 p.m., the licensee attempted to start Reactor Coolant System Makeup Pump 1-2 from the control room. When the pump did not start, an equipment operator went to the breaker cubicle and removed and reinserted the breaker control power fuse block. The Makeup Pump was started from the control room at 7:24 p.m.
The inspector's review of the licensee's evaluation of the event indicates that the fuse holder may have been loose from May 30 through June 9, 1989. The inspectors discussed this possibility with the licensee. The licensee is continuing its investigation. This is an unresolved item (50-346/89016-04(DRP)) pending the inspectors review of the licensee's continued investigation.
On June 12, 1989, at 4:48 a.m the No. 2 Control Room Normal Ventilation System tripped due to a spurious chlorine detector actuation. The operators attempted to restart the Ventilation System but the spurious actuation had not cleared. Control Room Emergency Ventilation System (CREVS) No. 1 was then started and secured at 5:40 a.m. when the chlorine detector was restored to
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k normal operation. On June 26, 1989, the licensee attempted to perform the monthly surveillance test on CREYS No. 1, but the compressor would not start. The unit was declared inoperable at 8:30 p.m. on June 26, 1989, and restored to operability at 2:55 p.m. on June 28, 1969. The licensee determined that CREVS No. I compressor failed to start because of a high pressure trip which does not give a control room alarm or a local alarm. The
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high pressure switch is located within Panel C6706.
The licensee's investigation revealed that on June 12 the CREVS system engineer and the zone operator observed that a status light on Panel C6708 indicated that CREVS No. 1 had switched over to the air cooled condenser which is an abnormal mode of operation. At 8:06 a.m., the zone operator had returned the unit to the water cooled mode and recorded the action in his log. Neither the CREVS system engineer nor the zone operator recognized the significance of that.
action. Operation of the CREVS in the air cooled mode requires the opening of manually operated valves or the unit will trip on high pressure. These valves were not opened on June 12th. The licensee postulates that the CREYS No. 1 compressor tripped when the unit switched to the air cooled mode during the approximate 52 minute operation of CREVS No. 1 on June 12, 1989.
The duration of the run was such that a change of control room temperatures would not have been noticeable. lhe licensee also determined that CREVS No. 2 was inoperable for maintenance from June 8, 1989, until 2:55 p.m. on June 12, 1989. Therefore, both trains of CREVS were inoperable from approximately 5:40 a.m. until 2:55 p.m. cn June 12, 1989, a period of approximately 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> and 15 minutes. This is a violation of Technical Specification 3.7.6.1 which requires two independent CREVS be operable when in Modes 1-4.
There is no action statement for having no CREVS available, thus Technical Specification 3.0.3 applies. The licensee did not initiate action to place the reactor in hot standby within one hour which is a violation (346/89016-05(DRP))
of Technical Specification 3.0.3.
This event is of minor safety i
significance because the CREVS would have performed all of its safety functions except cooling, and this would be quickly recognized and corrective actions taken.
The chlorine detector which caused the CREVS No. 1 to be started on June 12, 1989, is required by Technical Specification 3.3.3.7.
However, the chlorine detectors perform no safety function because the licensee no longer has significant quantities of chlorine stored on site and there is no other nearby source of chlorine. The licensee has submitted a License Amendment Request to the NRC requesting that the technical specification for ch1crine detectors be deleted from its license.
On June 16, 1989, the inspectors found five bolts loose in the doors l
of the EDG l-2 control equipment cabinets. The bolts are required to be tight to maintain the seismic qualification of the cabinets.
This is an example of inattention to detail. There is a sign on
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each door to remind personnel that the bolts are required for seismic l
qualification. The inspectors notified the shift supervisor and a
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short time later the inspectors observed an equipment operator tighten
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the bolts. The-inspectors discussed the condition with the equipment operator, the shift supervisor, the EDG system engineer and the Operations Manager.
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- 0n aune 22, 1989, an equipment operator noted that the air pressure gage for the Auxiliary Feedwater Pump Turbine (AFWPT) 1-1 steam admission valve (MS 58898)'was reading high off-scale. The licensee declared AFW System 1-1 inoperable and determined.that the air regulator-(Dresser Masoneilan Type 77-4) had failed open. The air regulator was replaced and AFW System-1-1 was declared operable.
Maintenance and' engineering details of this event are discussed in Paragraphs 7 and 10. The ccrrective actions for the failure included having the equipment operators record regulator air pressures _twice-each shift. On July 8 at 11:20 p.m., the inspectors reviewed the equipment operator's reading sheets and noted that the second air
, regulator reading for the 3:30 to-11:30 shift had not been recorded.
In a.later review of the equipment operator's reading sheets, the inspectors noted a late entry had been made indicating that the unrecorded reading had been taken but not recorded. The' licensee improved the reading sheets by providing a specific location for the air. regulator pressure reading.
On June 29, 1989, at 4:30 p.m., engineering personnel informed the Shift Supervisor that the response time requirements for the High Pressure Injection (HPI) System injection valves (HP2A, B, C, and D)
could not be met. The Shift Supervisor declared both trains of HPI inoperable and entered the appropriate technical specification action statements. HP2A, B, C, and D are normally closed motor operated valves (MOV) which must fully open during a Design Basis Accident (DBA). The licensee opened valves HP2C and D to their open (accident) position and declared HPI Train 1-1 operable at 5:02 p.m.
The licensee temporarily modified the controls for HP2A, B, C, and D to improve the valve response time and both HPI trains were declared operabic on July 1, 1989. Additional information about this event is provided in Paragraph 10.
On July 5, 1989, the inspectors noted that the Reactor Coolant System
'(RCS) hydrogen concentration written on the control room status board was out of specification (00S). The ins 3ectors reviewed the reading sheets provided to the control room by tle chemistry department and found a note on the June 30, 1989, reading sheet, with the 00S reading..The note stated that the chemistry technician thought that the 00S reading was invalid due to some equipment problems and that another sample would be taken on the next shift. No RCS hydrogen data _ appeared in the more recent reading sh:3ts. The inspectors brought this to the attention of a reactor operator. The operator contacted the chemistry department and found that the additional sample had been taken and was in specification but the reading had not been recorded on the July 1, 1909, reading sheet. This is another example of inattention to detail. The reactor operator made a late entry on the July 1, 1989, reading sheet and updated the control room status board.
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On July 9 1989, with the unit at 100% power Service Water (SW) Pump Ho. 1 failed to meet the acceptance criteria of Surveillance Test DB-SP-03017, " Service Water Pump 1 Quarterly Test." The shift supervisor declared SW locp 1 inoperable in accordance with Technical Specification 3.7.4.1 at 1:40 a.m.
The licensee aligned SW pump No. 3 to Loop 1 and declared it operable at 4:07 a.m.; thus SW Loop 1 was inoperable for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 27 minutes. Section 2.9 of Procedure SP1104.ll Revision 1S. " Service Water System Operating Procedure" states, "Whenever the Service Water System is inoperable because of failure, repair work in progress or routine maintenance on the system,.... The associated ECCS Train and Emergency Diesel Generator shall be declared inoperable." Technical Specification 3.8.1.1.b requires as a minimum, two EDGs be operable in Mode 1.
Action statement (a) for Technical Specification 3.8.1.1 states:
"With either an offsite circuit or diesel generator of the above required A.C. electrical power scurces inoperable, demonstrate the OPERABILITY of the remaining A.C. sources by performing Surveillance Requirement 4.8.1.1.1.a within one hour and at least once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter and by performing Surveillance Requirement 4.8.1.1.2.a.4 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />."
Surveillance Requirement 4.8.1.1.1.a states:
"Each of the above required independent circuits between the offsite transmission network and the onsite Class lE distribution system shall be determined OPERABLE at least once per seven days by verifying correct breaker alignments and indicated power availability."
The inspectors determined that neither the associated ECCS train nor EDGl-1 were declared inoperable as required by procedure
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SP 1104.11. This is a violation (346/89016-06A(DRP)) of Technical j
Specification 6.8.1 which requires procedures to be implemented.
Consequently, since the systems were not declared inoperable the licensee did not perform the required surveillance.
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The inspectors discussed these events with the licensee on July 18, i
1989, and its corrective action was to delete the procedural I
requirement to declare the associated ECCS system and EDG inoperable.
j This was accomplished by Temporary Approval TA89-4843 dated July 19, l
1989. 1he licensee stated that it was being removed because it did
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not need to be in the Limits and Precautions Section of the procedure.
The inspectors consider the removed sentence to be an action statement and concur that it is not a Limit or a Precaution.
I However, the action step belongs elsewhere in the procedure. This
is an unresolved item (346/89016-07(DRP)).
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On July 11, 1989, while verifying circuit breaker lineups the licensee discovered that MCC EF12C was aligned to Bus F12C and not Bus E12C as required. This electrical lineup did not provide electrical separation between SW pump No. 3 which was aligned to SW Loop 1 and SW pump No. 2 in that the strainers and blowdown valves were powered from the same source.
The licensee concluded that Procedure SP1104.ll was inadequate in that guidance in the form of a caution was given in Sections 4.0
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and 5.1 but there were no verification steps in either Section 5.2 or 5.4.
These are the sections used to place SW Pump 1-3 in service.
The licensee initiated a procedure change request (PCR)
to correct the procedural weakness. This is an example of procedural weaknesses resulting in operational problems.
The inspectors reviewed SP1104.11 and noted that Caution 4.1.6 in the startup section and Caution 5.1.4 in the abnormal operations section list the proper electrical lineup. The inspectors concur that there are no verification steps with replacing the operating SW pump with SW Pump 1-3 but conclude that there is sufficient information for the operator to have performed the proper electrical lineup. This is a violation (346/89016-06B(DRP)) of Technical Specification 6.8.1 which requires procedures be implemented.
On July 14, 1989, the licensee had an unplanned radioactive liquid release when approximately 1700 gallons of water were released from the Clean Waste Monitor Tank (CWMT) 1-1 rather than CWMT l-2 as planned. CWMT l-2 had been sampled in accordance with Technical Specification 4.11.1.1.1 which requires each batch of radioactive liquid effluents to be sampled and analyzed prior to the release.
The licensee determined that Step 5.12.13 of Procedure DB-0P-03011
" Radioactive Liquid Batch Release," had a typographical error which caused the operator to select the incorrect CWMT. This resulted in CWMT l-1 not being sampled before the contents were released which is a violation (346/89016-08(DRP)) of Technical Specification 4.11.1.1.1..The licensee determined that the only radioactivity in CWMT 1-1 was entrained noble gases and there was zero offsite dose.
This issue will be reviewed by a Regional inspector during a subsequent inspection.
The inspectors have reviewed Procedure DB-0P-03011 and in particular Section 5.12, " Performing a Clean Waste Monitor Tank 1-2 (CWMT l-2)
Release." Step 5.12.13 states, "If CWMT Transfer Pump 1-2 is being used to perform the release THEN lineup CWMT l-1 for Makeup / Discharge.
Normal Pump Lineup, in accordance with DB-0P-06105, (SP1104.83),
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Clean Waste Monitor Tank Operations." The inspectors have concluded that the operator followed the procedure and did not question the step in the procedure when the tank to be lined up was obviously in error. The inspectors reviewed both procedures associated with liquid radioactive waste discharges, DB-0P-03011 and DB-0P-06105. Their observations are discussed in Paragraph 11. On July 24, 1989, the licensee issued Temporary Approval TA89-4775 which corrected the typographical error and human factor deficiencies of Procedure DB-0P-03011, Section 5.12.
The inspectors met with licensee operations management several times during the reporting period to discuss some of the operational problems described in this report. They discussed the inattention to detail issues which are prevalent throughout the events and benefits of having the shift supervisor spend more time in the plant. Subsequent to these discussions, the inspectors met with the Plant Manager who stated that he had directed Operations Department
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management personnel to develop and implement a program to have the shift supervisors significantly increase the time they spent in the plant.
b.
Off-shift Inspection of Control Rooms The inspectors performed routine inspections of the control room-during off-shift and weekend periods; these included inspections between the~ hours of 10:00 p.m. and S:00 a.m.
The inspections were conducted to assess overall crew performance and, specifically,
control room operator attentiveness during night shifts.
The inspectors determined that both licensed and non-licensed operators were alert and attentive to their duties, and that the administrative controls relating to the conduct of operation were being adhered to.
c.
ESF System Walkdown The operability of selected engineered safety features was confirmed by the inspectors during walkdowns of the accessible portions of several: systems. The following items were included: verification
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that procedures match the plant drawings, that equipment, instrumentation, valve and electrical breaker line-up status is in agreement with procedure checklists, and verification that locks,.
tags, jumpers, etc., are properly attached and identifiable. The following systems were walked down during this inspection period:
Auxiliary Feedwater System
Service Water System-
High Pressure Injection System
Low Pressure Injection System Control Room Emergency Ventilation System
Direct Current Electrical Distribution System
d.
Plant Material Conditions /Houseke qing The inspectors performed routine plant tours to assess material conditions within the plant, ongoing quality activities and plant-wide housekeeping.
On May 19, 1989, an electrical fault caused safety related motor control center (MCC) E12B to be inoperable. The electrical fault was caused by a loose piece of wire which apparently reached the inside of the MCC through a small gap in the top of the MCC. The inspectors discussed this event several times with licensee personnel i
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and pointed out that other MCC's should be inspected and c1 caned as necessary. On June 9,1989, the inspectors also informed licensee personnel at the exit interview for Inspection Report No. 50-346/89014 that it would be prudent to seal the gaps on the tops of the MCC's and clean the tops of the MCC's. On June 27, the inspectors observed five loose small metal objects (nuts, wire, washers) on the top of DC MCC1, three metal bolts with washers on the top of Reactor Trip Breaker C
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s and small chunks of cementitious fireproofing on top of Reactor Trip Dreaker C.
On July 14th, the inspectors again observed metal and other cbjects on top'of electrical cabinets. They discussed their findings with licensee personnel after each tour. Shortly thereafter electrical maintenance personnel prepared a Maintenance Work Order to clean the tops of all nuclear safety related MCC's.
The poor housekeeping (practices which allowed this condition to exist is a violation 346/89016-09(DRP)) of 10 CFR 50, Appendix B, Criterion II which is implemented by the licensee's Nuclear Quality Assurance Manual (NQAM).
No other violations or deviations were identified.
6.
Radiological Controls (71707)
The licensee's radiological controls and practices were routinely observed by the inspectors during plant tours and during the inspection of selected work activities. The inspection included direct observations of health physics (HP) activities relating to radiological surveys and monitoring, maintenance of radiological control signs and barriers, contamination, and radioactive waste controls. The inspection also included a routine review of the licensee's radiological and water chemistry control records and reports.
Health physics controls and practices were generally satisfactory.
Housekeeping in the radiological controlled areas was generally satisfactory. Knowledge and training of personnel were generally satisfactory.
A licensee QA surveillance of the physical inventory and leak testing of fission detectors revealed that two fission detectors installed in October 1988 had not been leak tested within 31 days prior to installation as required by the TS. This is a violation (50/346-89016-10(DRP)) of TS Surveillance Requirement 4.7.8.1.2.
The licensee reported this violation in LER 89-006. The licensee will edd a step requiring a leak test to Procedure DB-PF-00100, " Fuel Handling Administration," by September 1, 1989. Once the fission detectors are installed no additional leak testing is required. The fission detector vendor informed the licensee that successful calibration of the fission detectors would indicate that there had been no leakage. The licensee is required to calibrate the fission detectors prior to use during the next refueling outage (scheduled to begin in February 1990). This violation has no safety significance and no notice of violation will be issued because the violation meets the requirements of 10 CFR 2, Section V.G.l.
No other violations or deviations were identified.
7.
Maintenance / Surveillance (61726, 62703, 92701, 93702)
Selected portions of plant surveillance, test and maintenance activities on systems and components important to safety were observed or reviewed to ascertain that the activities were performed in accordance with approved procedures, regulatory guides, industry codes and standards, and the l
Technical Specifications. The following items were considered during
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limiting conditions for operation were met while components or systems were removed from service; approvals were cbtained prior.to initiating work; activities were accomplished using approved procedures and were inspected as applicable; functional testing or calibration was performed prior to returning the components or systems to service; parts and materials used were properly certified; and appropriate fire prevention, radiological, and housekeeping conditions were maintained.
a.
Maintenance The reviewed maintenance activities ircluded:
Replacement of the air pressure regulator for the No. 2
Auxiliary Feedwater Pump Turbine (AFWPT) steam admission valve (MS 58898). The inspector's observations of the internals of the air regulator are discussed in Paragraph 10.
Replacement of the air pressure regulator for the No. 1
Auxiliary Feedwater Pump Turbine (AFWPT) steam admission valve (MS 5869A). The inspector's observations of the internals of the air regulator are discussed in Paragraph 10.
Installation of tira delay relays in breaker cubicles
for HP2A, B, C and D.
Main Steam Valve MS611 position indication troubleshooting
and repair.
Installation of fire damper in Low Voltage Switchgear
Room ventilation system.
Repair of Room Cooler for Emergency Core Cooling System Room
No. 3.
Some parts were not properly controlled by maintenance personnel on this job. This weakness was brought to the attention of Licensee Management.
Pressurizer level indication troubleshooting.
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Surveillance The reviewed surveillance included:
Procedure No.
Activity ST 5016.09 Fire Protection Valve Monthly Inspection ST 5032.02 Radiation Monitoring System Channel
Calibration DB-HI-03245 SFRCS Channel 1 Functional Test
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DB-PF-03220 Imbalance, Tilt and Rod Index
Calculations - Group 38 Alarms Inoperabic DB-PF-03230 Daily Heat Balance Check
DB-SC-03109 Safety Features Actuation System Overall Response ilme Calculation 08-S5-03041 Control Room Emergency Ventilation
System Train 1 Monthly Test DB-SP-03357 Reactor Coolant System Water Inventory
Balance On July 8, 1989, the shift superviser discovered that Surveillance Test ST5016.09, " Fire Protection Valve Monthly Inspection," had not been performed since May 3, 1989. This surveillance is performed to satisfy Technical Specification 4.7.9.1.1.c which requires that at least once per 31 days each valve in the flow path that is accessible be verified that it is in its correct position.
This is one of the requirements to demonstrate the fire suppression system operable. The shift supervisor then directed that the surveillance be performed and it was determined that sufficient valves were in their correct position to verify operability. Review by the licensee determined that at 12:22 p.m. on May 3, 1989, ST5016.09 had been suspended because five of the valves to be verified were out of position and the position of one other valve was indeterminate. The licensee again suspended ST5016.09 at 6:03 a.m. on May 15, 1989, due to out-of-position valves. An entry in the unit log denoting the May 15, 1989, surveillance suspension states that ST5016.09 was past the technical specification late date but the intent of Technical Specification 4.7.9.1.1.c to ensure a fire system flowpath was operable, was met. The licensee documented the missed surveillance in PCAQ 89-0356.
The licensee determined that the surveillance was suspended because the surveillance test acceptance criteria could not be met.
It also determined that surveillance tests which are suspended are not included in its surveillance performance alert list. HowcVer, there is sufficient information available for the licensee to have performed the test within technical specification requirements. The performance of ST5016.19 with an interval of 72 days is a violation (346/89016-11(DRP)) of Technical Specification 4.7.9.1.1.c which requires the surveillance to be performed at least every 31 days. This violation has no safety significance because the technical specification required fire suppression water system was operable.
l The licensee made a telephone report to the hRC for the above incident on July 8, 1989. This is a violation (346/89016-12(DRP)) of Technical Specification 3.7.9.1, Action Statement b.2(c), which requires telephonic reporting within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The delay in reporting had no safety significance.
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Additional review by the inspectors revealed that between December 13, 1988, and March 7, 1989, the licensee had difficulties in performing ST5016.09 on several occasions. The acceptance criteria could not be
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3 met. These were documented in PCAQ 89-0255. During February and March 1988 the licensee had isolated a non-technical specification section of the fire protection water system because of a leaking header. The inspectors had raised a question of operability and the requirement for a redundant supply. A conference call was made to NRR on March 8, 1988, to discuss the licensee's understanding of Technical Specification 3.7.9.1.c.
NRR stated that the loss of the yard loop (redundancy) did not make the fire system inoperable as icng as fire suppression water i
was available to suppression systems required by the Technical Specifications.
The inspectors have concluded that had the licensee modified its l
surveillance procedures to reficct the results of the March 8, 1988, conference call relating to determination of system operability it could have avoided these two violations. 1hese procedural problems are similar to those fire protection procedure concerns described in Paragraph 11.
Personnel performing maintenance or surveillance used correct procedures and proper werk control documents. Work authorization had been obtained for the jobs performed. Prerequisites for performing the job, such as worker protection and tagging had been performed.
No other violations or deviations were identified.
8.
Emergency Preparedness (71707, 82302)
An inspection of emergency preparedness activities was performed to assess the licensee's implementation of the emergency plan and implementing procedures. The inspection included monthly observation of emergency facilities and equipment, interviews with licensee staff, and a review of selected emergency im?lementing procedures. The inspectors reviewed the drill scenario for tie annual exercise which will occur during the next inspection period.
No violations or deviations were identified.
9.
Security (71707, 81700)
The licensee's security activities were observed by the inspectors during routine facility tours and during the inspectors' site arrivals and departures. Observations included the security personnel's performance associated with access control, security checks, and surveillance activities, and focused on the adequacy of security staffing, the security response (compensatory measures), and the security staff's attentiveness and thoroughness.
The security personnel were obscrved to be alert at their posts.
Appropriate compensatory measures were established in a timely manner. Vehicles entering the protected area were thoroughly searched.
No violations or deviations were identified.
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I 10. Engineering'and Technical Support (42700, 62703, 71707, 92701, 93702)
An inspection of engineering and technical support activities was performed to assess the adequacy of support functions associated with
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operations, maintenance / modifications, surveillance and testing activities. The inspection focused on routine engineering involvement in plant operations and response to plant problems. The inspection
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included direct observation of engineering support 45 activities and-
discussions with engineering, operations, and maintenance personnel.
l The inspectors have observed a continuing engineering presence in the plant relating to maintenance work and in response to plant problems.
j a.
On May 30 1989, while at 100% power, the reactor tripped on an
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anticipatory reactor trip signal when the' turbine tripped from j
high condenser pressure. A failed 4.6KV splice in the water
. treatment' plant resulted in the loss of a condensate pump. This event is described in Inspection Repart No. 50-346/89014. The'
licensee sent the failed splice (Phase A) and both adjacent splices to a laboratory to be cut open, inspected and analyzed.
" Splice j
failure" is a general description which includes failure of the-i actual conductor splice or failure of the splice insulation system.
I In this case the conductor splice did not fail, the splice insulation i
system failed. The manufacturer (Raychem) of the material used to insulate the splice had representatives present for the opening and inspection of the splices. Raychem also prepared an analysis of the splice failure. The inspectors reviewed the analyses and observed.
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the splices after they had been cut open for the analysis. The l
analyses determined that the failure was caused by improper cable l
preparation in which the semi-conducting layer.was not removed from the new cable that was spliced to the existing cable. The inspection revealed that tracking was present along the surface of the extruded semi-conducting layer from the conductor to the edge of the metallic
shielding. The outer most tubing of the Raychem splice was bulged
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adjacent to the burn area. The licensee theorizes that the bulge occurred as the result of gases produced from electrical tracking i
along the semi-conducting layer. The investigation determined that j
phase C was prepared by a different crew and Phase B was prepared i
by a contractor. The licensee stated that no safety related cables i
have splices. The inspectors have reviewed both the laboratory and
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Raychem reports.
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b.
The inspectors met with engineering personnel to discuss the effects
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of the two power increases, described in PCAQ 89-0296, which occurred
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during power escalation on May 31, 1989. The inspectors asked about l
the effects of the described power increases and requested clarification of the term " rate." The licensee agreed to contact
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Babcock and Wilcox (B&W) and have it respond to two questions about i
the power escaletion. B&W stated in its response (BWT-89-3029, dated June 22, 1969) that there were no immeciate or potent %1 effects from the power level changes of May 31, 1989. B&W further stated that the maximum power change in any one step change shall be 1/3 of the power change permitted in one hour but not to exceed 5 percent of full power and step changes should be as evenly spaced as possible.
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-1 The licensee plans to change its procedures to incorporate the B&W guidance. The inspectors consider that the questions raised Dy the PCAQ have been adequately answered.
c.
On June 2?, 1989, the air pressure regulator for the No. 1 Auxiliary Feedwater Pump Turbine (AFWPT) steam admission valve (HS 5889A)
failed open. The failure was caused by fe.iled threads on a plastic part inside the regulator.
It appears that the plastic part failed due to exposure to heat. The regulator is directly attacheo t>
MS 5889A and is heated by conduction f rom the valve yoke as well as convection and radiation from steam piping and the uninsulated valve bonnet. Elastomeric parts inside the regulator had also become brittle, but did not appear to have contributed to the failure.
Because of the failure cf the MS 5889A air regulator, the No. 2 AFWPT steam admission valve (MS 5869B) air regulator was replaced on July 7, 1989. The regulator appeared to be operating pro)erly just prior to its removal; however, when it was tested in the slop after removal it tailed open.
Inspection of the regulator internals revealed no apparent reason for its failure, although there was some deterioration of elastomeric components.
Valves MS 5889A and B were not designed to be operated with air at instrument air header pressure, therefore a failed open air regulator could cause the AFWPT to fail to start or to start more slowly i.han required. After evaluating the condition discovered, the licensee replaced the air regulators with identical regulators, as an interim solution. This decision was based on the demonstrated service life of the air regulator that failed and the licensee's i
plans to replace the regulators at three month intervals until a I
suitable replacement is installed. The licensee is also recording the air regulator pressure six times a day to allow early detection of any degradation of air regulator performance. The inspectors reviewed several days of Zone Operator's readings sheets to verify that the air regulator pressure is being recorded.
The licensee is continuing its evaluation of this event and this will remain an unresolved item (50-346/89016-13(DRP)) until the inspectors complete their review of the licensee's root cause determination.
d.
On June 29, 1989, citer discussion with licensee training personnel, licensee engineering personnel found that the normally closed motor operated High Pressure Injection (HPI) valveF (HP2A, B, C, and D)
would take about fifteen seccnds longer to open than the 35 seconds previously assumed. This condition appears to have existed since about 1977 and would have occurred only if a loss of offsite power coincided with a loss of coolant accident.
Initially the emergency diesel generator load sequencers would provide a start signal for the valves. Three seconds later the start signal is blockad. Once they receive a start signal most motor operated valves would continue to travel to their required positions without interruption because the controllers for each valve have a " seal in" circuit. However, the controller for HP2A,B,C, and D did not have seal in circuits because the valves may nced to be throttled from the control room
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during some postulated accidents. Therefore, in the past, when the
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start signal for HP2A,' B, C, and D was blocked, the valves would stop. At three seconds, the valves would be about 20 percent open.
.The.sequencers unblock the start signal about fifteen seconds after it was blocked and at that time the valves would continue to open.
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The licensee's preliminary review of the delay in opening the. valves.
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indicates.that the plant probably ht:1 remained within the bounds of-t the_ existing DBA analyses because the partially open valves would have allowed injection flow to begin. The licensee is having B&W provide a detailed analysis of the condition..The licensee prepared a Temporary Modification (TM) for each valve to install a timing relay to' provide a temporary seal in' circuit so that the initial
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-three-second start signal would allow the valve.to fully open. The
~ inspectors reviewed the.TM documentation, observed installation cf two of the timing relays, ar.d observed and reviewed post modification, testing. The valves functioned as required during the testing..The
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inspectors noted that the the licensee's.10 CFR'50.59 evaluation of
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the TM concluded that the addition of the the time. delay relays did not involve'an unreviewed safety question because.the added-probability of failure of-the. timing relays was small compared with the premodification probability of failure of the. system.
The-
. inspectors reviewed the May 12, 1988, letter from the NRC (Rossi) to NUMARC'(Tipton) commenting on the joint NUMARC/NSAC working group draft 10 CFR 50.59 guidance document.
.The discussion of Issue
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No. 2 in Enclosure 1 and Comment.(6) in Enclosure 2 appear to indicate that any increase no matter how small, in the probability of failure of a safety system is an unreviewed safety question. This is an L
unresolved item (50-346/89016-14(DRP)).until the inspectors can review the licensee's analysis of the as-found condition and determine what change in probability constitutes an unreviewed
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safety question.
e.
On July 11, 1989, the inspectors met with the Fire Compliance Supervisor to discuss various fire protection items. The. inspectors reviewed the large number of spurious fire alarms which occurred during the inspection period. The licensee believes that the large number of spurious fire alarms can be attributed to multiplexer and it is working on correcting this deficiency.
The schedule for completion of.the Appendix "R" work was reviewed and the licensee believes that the required work will not adversely affect the next refueling outage. The inspectors questioned the licensee as to the quality of fire protection walkdowns. The inspectors have observed-that some areas have been walked down three or four times and additional items are identified during each walkdown. The licensee stated that it was also concerned with the continued identification of items which should have been identified.previously. This area will be examined during subsequent inspections.
The inspectors observed that s%e fire protection procedures had been issued with known deficiencies (e.g., Procedure DB-FP-04002,
" Monthly Fire Hose House Inspection," was issa d with a list of required equipment for each hose house that had not been validated with the existing equipment and the differences resolved). This was
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because of.the large. number of deficiencies which had been identified.
The-inspectors were concerned that the use of deficient procedures could condition the users to ; cept the use of incorrect procedures.
The. inspectors discussed their concerns with the licensee and were.
' told that the new procedures were better than the old. The licensee-stated when questioned that the new procedures with their known deficiencies better demonstrated the operability of the equipment
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than the old procedures. The use of deficient procedures is a violation (346/89016-15(DRP)) of 10 CFR 50, Appendix B, Criterion V, which requires activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances.
The inspectors elevated their concerns to engineering management.
They informed the licensee that this condition was similar to those described in Inspection Report No. 50-346/88012(DRP)). Engineering management concurred with the inspectors' concerns and directed that only correct procedures be issued. The inspectors have not observed the use of incorrect fire protection procedures anc will verify the adequacy of-licensee's corrective action.
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f.
The inspectors reviewed NUREG/CR-5078, "A Reliability Program for Emergency Diesel Generators at Nuclear Power Plants" and discussed its content with licensee engineers. The licensee also reviewed the NUREG and identified possible improvements in its Emergency Diesel Generator (EDG) reliability program. Some improvements, which would require equipment modifications and procedure changes, are being evaluated in more detail by the licensee. The licensee is also
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developing an action plan for EDG reliability program improvements.
l The inspectors will review the licensee's efforts in this area in a future inspection.
No other violations or deviations were identified, 11. Safety Assessment / Quality Verif_ication (30703, 40500, 93702)
i An_ inspection of the licensee's quality programs was performed to l
assess the implementation and effectiveness of programs associated with management control, verification, and oversight activities. The a
inspectors considered areas indicative of overall management involvement in quality matters, self-improvement programs, response to regulatory and roomobservations,andmanagementpersonnelgementplanttoursandcontrol industry initiatives, the frequency of mana s participation in technical and planning meetings. The inspectors reviewed Potential Condition Adverse to Quality Reports (PCAQ), Station Review Board (SRB) and Company Nuclear Review Board meeting minutes, event critiques, and related documents; focusing on the licensee's root cause determinations and corrective actions. The inspection also included a review of quality records and selected quality assurance audit and surveillance activities.
Performance in this area included the following major items:
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On May 31, 1989, during the previous inspection period a reactor trip occurred as a result of high condenser pressure. This event-was described in Inspection Report No. 50-346/89014(DRP). During
.the trip recovery, Quality Assurance (QA) personnel performed a surveillance of control room activities-which is documented in
.QA Surveillance Report No. SR-89-PLOPS-11 dated July 5, 1989.
Procedure DB-0P-06901, " Plant Startup," Section 7.2.5.a states that, "The maximum rate of power increase below 20 percent RTP (Reactor Thermal Power) shall be 10 percent RTP per hour," and'
is repeated in Note 7.4.2.
The Surveillance Specialist observed that on two occasions. power increased at a rate greater than 10 percent per hour.
In the first instance power was increased 5.58 percent in 30 minutes and in'the'second instance power was
. increased 3.98 percent in 12 minutes. Each power increase did not exceed 10 percent in one hour but, in the specialist's opinion, the increase exceeded the 10 percent per hour rate limitation.- This observation was documented in PCAQ No. 89-0296 dated June 2,:1989.
The PCAQ generated'a great deal of interest because there was no consistent definition of rate. Some believed that step. increases were acceptable while others believed that the increase should be accomplished by ramp increases. The inspectors noted that the smallest increment that the operators could observe on the nuclear instrumentation has one percent which would in effect control the manner in which power was increased. The inspectors met with various licensee personnel to discuss various aspects of the power increase.
The inspectors asked engineering personnel what the effects were of the two power increases described in PCAQ 89-0296 and to define rate.
The engineering response is discussed in Paragra;h 10.
b.
On July 11, 1989, a security officer walked into a scaffold in a dimly lit area of the plant. The individual sustained a possible injury to his neck and was transported to the hospital for observation. The inspectors discussed this event with security management and reviewed an earlier safety report in which another security officer had reported that the area was poorly lighted and an injury could result from the lighting conditions. After the safety report was issued a plant safety inspector inspected the area and determined that lighting in the area was adequate. The inspectors suggested to the Safety Section after the officer was injured that it might want to revisit its original finding. The
. inspectors determined that the original evaluation was based on observation rather than by measurement. The licensee measured the lighting levels in several areas and determined it does not meet ANSI standards in three areas. Request for Assistance (RFA) 89-1218 was initiated to provide additional lighting.
c.
As a result of the July 14, 1989, unplanned radioactive liquid release, the inspectors reviewed Procedures DB-0P-03011, " Radioactive Liquid Batch Release" and DB-0P-06105, " Clean Waste Monitor Tank Operations." The inspectors review revealed that Procedure DB-0P-03011 was not clear and required the use of Procedure DB-0P-06105 to be accomplished. Procedure DB-06105 states that radioactive liquid a
releases are accomplished by Procedure DB-CH-03017. This was l
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implemented by Change No. 3, dated November 16, 1968. The inspectors determined that Procedure DB-CH-03017 had been superseded by DB-0P-03011 on November 16, 1988. The inspectors have asked the licensee why a procedure would be incorporated into another procedure and simultaneously superseded. The licensee is in the process of responding.
d.
The inspectors have concluded that procedural issues have been the cause of many of the problems which occurred during the inspection period. Failure to follow a procedure by not declaring a system inoperable resulted in a missed technical specification surveillance.
Poorly phrased / inadequate procedures and inattention to detail resulted in a missed technical specification surveillance and an incorrect electrical lineup.
These problems i.e. issuance of incorrect procedures, use of procedures which do not follow current practice and poor procedure review are reminiscent of the procedural problems described in Inspection Report No. 50-346/88012(DRP). The licensee has made significant improvements in its procedure program but must continue to focus management attention in this area to ensure past practices do not recur.
e.
The licensee is conducting a Safety System Functional Inspection (SSFI) of the Instrument Air System.
So far the licensee has identified three significant findings. These findings will be discussed in a later inspection report.
12. Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, er deviations. An unresolved item disclosed during the inspection is discussed in Paragraphs 5 and 10.
13. Exit Interview (30703)
The inspectors met with licensce representatives (denoted in Paragraph 1)
throughout the inspection period and at the conclusion of the inspection and summarized the scope and findings of the inspection activities. The licensee acknowledged the findings. After discussions with the licensee, the inspectors have determined there is no proprietary data contained in this inspection report.
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