ML17180A639
| ML17180A639 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 03/08/1994 |
| From: | Hiland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17180A636 | List: |
| References | |
| 50-237-94-02, 50-237-94-2, 50-249-94-02, 50-249-94-2, NUDOCS 9403220062 | |
| Download: ML17180A639 (21) | |
See also: IR 05000237/1994002
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION -I I I
Report Nos. 5ti-237/94002(DRP); 50-249/94002(DRP}
Docket Nos. 5'0-237; 50-249
Licensee:
Commonwealth Edison Company
Opus West III
1400 Opus Place - Suite 300
Downers Grove, IL 60515
Facility Name:
Dresden Nuclear .Power Station, Units 2 and 3 *
Inspection At:
Morris, IL
Inspection Conducted: January 11 through February 22, 1994
Inspectors:
Approved By:
M. Leach
A. M. Stone
D. Chyu
Prl //1J!_
P. L. Hiland, Chief
Reactor Projects Section 18
Inspection Summary
Inspection from January 11 through February t2, 1994 (Report N6s.
50-237/94002(DRPl: 50-249l94002CDRP))
.
Areas Inspected: Routine, unannounced resident inspection of operational
safety verification and engineered safety feature (ESF) system walkdown;
maintenance and surveillance observations; engineering and technical support
observations; plant support observations; safety assessment and quality
verification; reactor water level instrumentation; licensee action on previous
inspection findings; and licensee event report review.
Results: Of the eight areas inspected, no violations or deviations were
identified in five areas.
One apparent* violation for inadequate or untimely
corrective actions was identified in paragraph 8.
One violation for the
failure to submit a licensee Event Report when reactor water level switches
were found out of technical specification limits is discussed in paragraph
5.a.
One deviation from a commitment in response to Generic letter 89-13 is
discussed in paragraph 3.a.
9403220062 6§856~37
~DR ADOCK
Assessment of Plant Operations
An equipment Operator was attentive to equipment status and identified a
faulty diesel generator air regulator valve. Operations management showed
leadership and direction during a potential Unit 3 shutdown due to two
inoperable diesel generators. Actions for a controlled, planned shutdown were
discussed with the operating crew in the event the shutdown was n~cessary.
However, management expectations regarding procedure adherence were not
clearly delineated and resulted in an NRC identified deviation from a
commitment.
In addition, the lack of management oversight resulted in ingress
of service water to the Unit 1 containment.
-
Assessment of Maintenance and Surveillance
Numerous improvement efforts in the instrument maintenance area were initiated
and demonstrated good management attention and worker response. Coordination
and execution of maintenance activities on the Unit 2/3 and Unit 3 diesel
generators were good.
However, instrument mechanics did not retain failed
mercury switches for root cause evaluations.
Assessment of Engineering and Technical Support
Site engineering support to operations and maintenance on the Unit ~/3 diesel
generator air regulator failure was good.
The evaluation which considered the
impact of increased air pressure on equipment downstream of the faulty valve
was thorough.
System engineering involvement and support to maintenance on
the Unit 3 diesel generator was good.
-
Site and system engineering did not recognize the significance of the reactor
water level instrument adverse performance trend.
No root cause
determinations were completed for failed switches.
The numerous failures
within the past year indicated licensee action to resolve this issue was not
commensurate with the safety significance of the problem. Also, the licensee
did not submit written notification for failed reactor water level switches
and resulted in an NRC identified violation.
Numerous weaknesses were
identified in one licensee event report. After the reactor water level
instrumentation issue was brought to engineering's attention, the performance
of site engineering was aggressive and appropriate.
Assessment of Plant Support
The newly formed composite cleaning crews was a good initiative to
systematically clean and decontaminate areas in the plant.
The untimely
distribution of Information Notices was a weakness.
Assessment of Safety Assessment and Quality Verification
Management did not ensure appropriate actions were taken to resolve the
recurring reactor water level instrument failures and drifts.
2
- ._
1.
DETAILS
Persons Contacted
- M. Lyster, Site Vice President
- G. Spedl, Manager, Dresden Station
- R. Aker, Technical Services Superintend~nt
- M. Korchynsky, Senior Operating Engineer
- J. Kotowski, Operations Manager
- H. Massin, Engineering Manager
- T. O'Connor, Maintenance Superintendent
- B. Palagi, Unit 1 Project Manager
- R. Radtke, Services Superintendent
R. Robey, Director, Safety Quality Verification
- J. Shi e.l ds, Regulatory Assurance Supervisor
- M. Strait, Technical Staff Supervisor
J. Williams, Operations Support Supervisor
- Indicates persons present at the exjt interview on February 23, 1994.
The inspectors also contacted other licensee personnel including members
of the operating, maintenance, engineering, and plant support
departments.
2.
Summary of Operations
3.
Unit 2
The unit operated at power levels up to 99% power.
The unit was derated
due to feedwater fl ow nozzle ca 1 i brat ion discrepancies.
Unit 3
The unit continued coasting down throughout the period.
Plant Operations (71707, 71710 & 93702)
The inspectors verified that the facility was operated in conformance
with the licenses and regulatory requirements and that the licensee's
management control system was effectively carrying out its
responsibilities for safe operation. During tours of accessible areas
of the plant, the inspectors made note of general plant and equipment
-conditions, including control of activities in progress.
On a sampling basis the inspectors observed control room staffing and
coordination of plant activities, observed operator adherence with .
procedures and technical specifications, monitored control room
indications for abnormalities, verified that electrical power was
available, and observed the frequency of plant and control room visits
by station managers.
The inspectors also monitored various
administrative and operating records.
3
The inspectors observed good equipment operator (EO) attention to plant
equipment and good operations management.
Specifically;
An EO identified a faulty air regulator valve on the Unit 2/3
diesel generator (DG) on February 3 and the DG was declared
inoperable. Verification of proper air pressu~e was not required
on that shift.
Operations management showed good leadership and direction during
a potential Unit 3 shutdown due to two inoperable diesel
generators. Actions for a controlled, planned shutdown were
discussed with the operating crew in the event the shutdown was
necessary.
Accessible portions of ESF systems and associated support components
were inspected to verify operability through observation of
instrumentation and proper valve and electrical power alignment.
The
inspectors also visually inspected components for material condition.
Specifically, the following systems were inspected by direct field
observations:
Unit 3 and Unit 2/3 DGs
Units 2 and 3 reactor water level instrumentation
Plant Operations Observations
a .
Deviation From Commitment Due to Procedural Adherence Error
During the performance of Special Procedure 93-11-110,
"Differential Pressure Test of MO 3-1501-138," revision 0, the
licensee failed to perform a step resulting in a deviation from a
commitment.
Step I.4.a required chemical injection to be
initiated. This step was annotated by the reactor operator "NA
(not applicable) system frozen."
The next step instruct~d the
operator "WHEN Sodium Hypochlorite injection into the Circulating
Water System is initiated, THEN IMMEDIATELY perform the following:
(1) Start 3A containment cooling service water (CCSW) pump, (2)
Start 3D CCSW pump."
The operator performed these steps although
chemical injection was not in service.
The inspectors noted that
the chemical injection system had been frozen since December 30,
199~. The system was repaired on February 17, 1994.
No
injections to Units 2 & 3 CCSW intake bays occurred during this
time period.
The inspectors queried operations management on procedure
adherence expectations in this situation. The inspectors reviewed
Dresden Administrative Procedure (OAP) 9-11, "Conduct of
.
Surveillance, Special and Complex Procedures," which stated that
if a step cannot be performed then document the problem and the
basis for continuing. This was not performed in this case. The
inspectors reviewed OAP 9-13, "Procedural Adherence," which stated
(1) if a step cannot be performed the supervisor shall determine
4
b.
if work can be continued; or (2) if work cannot continue within
the constraints of the procedure, a procedure change shall be
initiated. The above administrative procedures provided confusing
guidance on procedural adherence.
The administrative procedures
were generally cumbersome and difficult to use.
For example DAP
09-01, "Station Procedures," referred to DAP 09-11, "Procedure
Usage and Adherence," which was actually DAP 09-13, "Procedural
Adherence."
DAP 09-01 also referred to DAP 09-13, "Procedural
Response to Abnormal Conditions," which did not exist.
DAP 07-02,
"Conduct of Operations," also provided some guidance on procedure
usage.
Not one of these documents provided a clear and concise
expectation with regards to procedure adherence.
Generic Letter 89-13, "Service Water System Problems Affecting
Safety Related Equipment," required licensees to take actions to
ensure service water systems remained reliable. One requirement
was to implement and maintain an ongoing program of surveillance
and control techniques to significantly reduce the incidence of
flow blockage problems as a result of biofouling.
In a letter to
the NRC on January 29, 1990, the l i cens.ee committed that for open
cooling water systems, a biocide would be injected manually into
the intake bay during operation.
Between December 30, 1993, and
February 17, 1994, the CCSW systems for Units 2 and 3 were
operated on several occasions without biocide addition to the
intake bays. This is a Deviation from commitments made in
. response to Generic Letter 89-13 (50-237 /94002-01 (DRP. The root cause for this deviation was delayed maintenance actions coupled with inadequate procedural adherence. The licensee completed an investigation into procedure adherence problems and initiated a revision of the administrative procedures. The licensee provided a "Basic Expectations" document to employees which stressed procedure adherence. The inspectors will continue to monitor the licensee's efforts to improve procedure adherenc~. Operational Events During the inspection period, events occurred which were reviewed by the inspectors for the immediate licensee actions. The licensee's root cause investigation and corrective actions will be reviewed during future inspection activities. On January 25, 1994, the licensee discovered about four feet of contaminated water* in the Unit 1 containment basement. The licensee found several service water pipes cracked due to freezing conditions. No heat was provided to the Unit 1 containment. A special NRG team of eight regional and headquarters inspectors investigated the root cause and. corrective actions. The special team findings were documented in Inspection Report 50-010/94001. 5
.,
On February 2, 1994, the licensee identified containment isolation valve 3-2599-SA had exceeded its maximum stroke time on January 24. The licensee's final assessment of that anomaly was ongoing at the end of the inspection period. No violations were identified. One deviation from a 'commitment in response to Generic Letter 89-13 was identified. 4. Monthly Maintenance and Surveillance (62703 and 61726) Station maintenance and surveillance activities were observed and/or reviewed to verify compliance with approved procedures; regulatory guides, and industry codes or standards, and in conformance with technical specifications (TS). The following items were considered during this review: approvals were obtained prior to initiating the maintenance work or surveillance testing and operability requirements were met during such activities; functional testing and calibrations were performed pripr to declaring the component operable; discrepancies identified during the activities were resolved prior to returning the component to service; quality control records were maintained; and activities were accomplished by qualified personnel. The inspectors observed portions of the following maintenance activities: Unit 3 Investigation and repair of Unit 3 DG cooling water leak Repair of Unit 2/3 DG air regulator valve The inspecto~s also witnessed portions of the following test activities: Unit 2 DIS 287-03 . Auto Slowdown Permissive Low Pressure Coolant Injection and Core Spray Pump Discharge Pressure Switches DIS 0500-03 Reactor Water Level Emergency Core Cooling System (ECCS) Initiation Indicating Switch Calibration Unit 3 DIS 0500-03 Reactor Water Level ECCS Initiation Indicating Switch Calibration _ DOS 6600-01 Diesel Generator Surveillance Test DOS 1600-05 Unit 3 Quarterly Valve Testing 6
Maintenance and Surveillance Observations a. Improvement Activities in Instrument Maintenance The inspectors observed some significant improvement in the performance of the instrument maintenance department during.this inspectio~ period. This improvement began with a clear statement of expectations from senior management, and was followed by improved leadership by middle management. This. resulted in the following activities:
A reduction of 100 work requests in 5 weeks in the instrument de~artment work request backlog. Development of a minor instrument maintenance procedure to allow minor work activities without a work package. Establishment of a status board which showed the current state. of the instrument maintenance department backlog. Improved involvement of technicians in solving long standing problems with equipment and work practices. One improvement involving the traversing incore probe reduced the likelihood of contamination and personnel overexposures. Of particular note was the enthusiasm of some of the workers to drive the backlog to zero. The inspectors will continue to monitor these developments and will look for similar improvements in the other maintenance areas. b. Maintenance work on Unit 2/3 and Unit 3 Diesel Generator On February 2, the licensee observed increased crankcase pressure due to water intrusion during Unit 3 DG testing. The licerisee declared the DG inoperable and entered a seven day limiting condition for operation (LCO). The licensee determined the cooling water heat exchanger was the source of the water leak and commenced repairs. On February 3, an equipment operator identified a faulty air regulator on the Unit 2/3 DG. The licensee declared the Unit 2/3, DG inoperable and initiated a 24 hour LCO. Maintenance personnel replaced the air regulator and site engineering evaluated the effect of increased pressure on other valves downstream of the failed regulator *. The licensee did not identify any problems and declared Unit 2/3 DG operable within the LCO time limit. On February 6, the licensee declared the Unit 3 DG operable after replacement of the heat exchanger and , engineering evaluation of the water in the lube oil system. The inspectors observed various. portions of the maintenance activities and had no concerns.* Coordination and execution of maintenance activities on the Unit 2/3 and Unit 3 diesel generators were good * 7
5.
c . Safety Relief Valve Testing Following a concern over the adequacy of safety relief valve testing at the LaSalle station, the inspectors reviewed the method used for scheduling testing at Dresden station. The test method at Dresden included 50% of the safety relief va:lves in one refueling outage, the other 50% in the next outage. Each valve was therefore tested in alternate outages with a periodicity of 3 to 4 years depending on refueling intervals. This fell within the required 5 year period. The inspectors had no concerns. No violations or deviations were identified. Engineering and Technical Support (37700) The inspectors evaluated the extent to which engineering principles and evaluations were integrated into daily plant activities. This was accomplished by assessing the technical staff involvement in non-routine events, outage-related activities, and assigned TS surveillances; observing on-going maintenance work and troubleshooting; and reviewing deviation investigations and root cause determinations. Engineering and Technical Support Events a. Failure to Submit Licensee Event Reports Numerous failures and drifts of reactor water level instruments are discussed in paragraph 8. The licensee submitted licensee event reports (LERs) in January and October 1993 when multiple contacts were found outside TS tolerances, concurrently. However, * the licensee did not submit LERs for the remaining surveillance failures. 10 CFR 50.73 required written notification for any condition that could have prevented the fulfillment of a safety function. NUREG-1022, "Licensee Event Report System," stated " ... judgment must be made whether a failure that did actually disable one train of a safety system, could have, but did not affect a redundant train* within an ESF system. If so, this would constitute an event that 'could have prevented' the fulfillment of a safety function, and, accordingly, must be reported." Further clarification*was presented in example C-8 which stated an event was reportable if it was indicative of a generic and/or repetitive problem in several safety systems. The numerous (17 over 6 months) random failures of these switches were indicative of a recurring generic equipment problem. Failure to submit LERs is considered a Violation of 10 CFR 50.73 (50-237/94002-02(DRP)). b. Poor Quality of Licensee Event Report 237/93031. Revision 0 In January 1994, the licensee submitted LER 50-237/93031, "Reactor Vessel Level Instrumentation Found Outside of Technical Specification Due to Instrument Drift." The inspectors noted the following weaknesses in the report: 8
The licen~ee stated "several" dritts occurred with this instrument since installation. Within. a seven month period, the identical switch drifted seven times. The licensee listed one previous event (LER 249/93019); however, three LERs were written in 1993 regarding reactor water level switches out of tolerance. Also, no related _ problem identification forms (PIFs) were referenced. No previous industry experiences were provided. A LER submitted in January 1993 on reactor water level instruments listed 129 previous industry failures. The licensee stated LERs will be submitted for complete failures of logic and all other drifts or failures would be reported in a supplemental report at the:end of the year. This action was inconsistent with 10 CFR 50.73(f). The inspectors discussed these observations with the regulatory assurance supervisor. The inspectors noted improvement in a supplemental report of a related LER submitted in February. c. Diesel Generator Cooling Water Pump Degraded Flow On August 27, 1993, during a routine Unit 2/3 DG test, the licensee noted decreased cooling water (DGCW) flow. The design. flow rate was 840 gpm at a service water temperature of 95°F; however, only 640 gpm was achieved. At the time of the surveillance, all four CCSW pumps were supplying water to a discharge header common to the DGCW pumps .. After securing two CCSW pumps, the DGCW flow rate increased to 870 gpm. The licensee declared the Unit 2/3 DG inoperable for further engineering . evaluation. On August 31, the licensee performed an engineering operability evaluation which showed that a minimum DGCW flow of 640 gpm at 87°F was required to maintain Unit 2/3 DG operability. The DG was declared operable. On October 8 the temperature limit was lowered to 83°F based on information obtained during a Unit 2 DG test. On December 20 the licensee performed a more detailed calculation and determined the maximum DGCW intake temperature to be 86°F at 640 gpm. The inspectors reviewed these calculations and had no concerns. On January 19, 1994, the licensee performed a DGCW _hydraulic and thermal capacity test to confirm the latter calculation results. The inspectors will evaluate the test results during review of the associated licensee event r_eport (LER 237-93018, revision 2). d. Motor Operated Valve Testing The inspectors witnessed portions of the differential pressure * test of motor operated valve 3-JSOl-138, low pressure coolant injection minimum flow valve. The test was well coordinated and had sufficient resources to minimize th~ time equipment was 9
inoperable. The inspectors reviewed the test documentation and had no concerns with the differential pressure test. However, during the course of the review some concerns were identified as discussed in paragraph 3.a. One violation was identified for the f~ilure to submit licensee event reports. - 6. Plant Support (71707 and 93702) The inspectors evaluated the involvement of support organizations in assuring safe and effective plant operation. Specific areas included: Radiation Protection Controls The inspectors verified workers were following health physics procedures .and randomly examined radiation*protection instrumentation for operability and calibration. Security During the inspection period, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to the approved security plan. No discrepancies were identified.
- Emergency Preparedness
The inspectors verified the opetational readiness of the control room, technical support center, and operation support center. Non-routine events were reviewed to insure proper classification and appropriate emergency management involvement. Housekeeping and Plant Cleanliness The inspectors monitored the status of housekeeping and plant _ cleanliness for fire protection and protection of safety-related equipment from intrusion of foreign material. The station has implemented a composite cleaning crew, consisting of personnel from all station departments. The crew commenced cleaning the Unit 3 {elevation 517} and appeared to be effective in both cleaning and decontaminating the overhead areas. Plant Support Related Observations Information Notice Backlog The inspectors reviewed the licensee's actions in response to - Information Notice 89-77, Supplement 1, "Debris in Containment Emergency Sumps and Inc6rrect Sc~een ~onfigurations," which was issued- December 3, 1993. As of February 18, 1994, the licensee had not assigned this 10
information notice for action. Therefore, no action had been taken on this item to date. A further. review showed numerous information notices were backlogged in the regulatory assurance department. This demonstrated a weakness with regards to disseminating potentially safety significant information to the engineering personnel. The licensee's inspection of the emergency sumps and screens and sub~equent actions is an Inspector Follow-up Item (50-237/94002-03(0RP)). No violations or deviations were iderttified. 7. Safety Assessment and Quality Verification CSAOVl C40500l , The effectiveness of management controls, verification and oversight activities in the conduct of jobs observed during this inspection were evaluated. Management and supervisory meetings involving plant status were attended to observe the coordination between. departments. The results of licensee corrective action programs were routinely monitored by attendance at meetings, discussion with plant staff, review of deviation reports, and root cause evaluation reports.
- The inspectors reviewed the licensee's problem identification forms
(PIFs) to monitor the condttions related to plant or personnel performance and potential trend. The inspectors noted more safety significant PIFs were being submitted by licensee personnel. Also, through the PIF process licensee personnel identified numerous opportunities to enhance current programs. However, the licensee did not recognize the adverse trend on the reacto~ water level instruments. No violations or deviations were identified. 8. Reactor Water Level Switches Out Of Tolerance a. Design The emergency core cooling systems.(ECCS) were designed to actuate at certain reactor water levels to mitigate the consequences of an accident. Each unit had four level instruments. Each_ instrument had two mercury switches and associated contact pairs which sensed "low-low" reactor water level and initiated ECCS equipment when the one-out-of-two twice logic was satisfied. One additional set of con~acts on two level instruments provided the high reactor water level isolation signal for the high pressure coolant
injection (HPCI) system in a two-out-of-two logic. Technical specification (TS) tables 3.2.1 and 3.2.2 required the low-low level switches to actuate between 88 and 84 inches from the top of active fuel. This value corresponded to -59 and -SS inches medium range. The licensee set the switches to actuate at -57 inches. The TS required two channels per trip system operable. One inoperable channel in each trip system required a unit shutdown. * 11
b. The Updated Final Sjfety Analysis Report (UFSAR) Section 7.3.2.4 stated HPCI automatically isolated upon an increase in normal operating level of about 12 inches of water. This corresponded to +48 inches on the medium range and was 90 inches below the steam line outlet. The licensee set the switches to actuate at 46 inches, +/- 2 inches.
Equipment History As discussed in In~pection Reports 50-237/92036 and 50-237/93034, the ECCS level switches had a history of failures to actuate within the technical specification limits. Since 1991, the instruments were out-of-tolerance or completely failed to actuate at least 50 times. The Dresden Vulnerability Assessment Team reviewed the history between 1989 and 1991 and determined that twenty five percent of the 30 out-of-tolerance (OOT).events were complete failures to actuate. The 1992 through 1994 data is summarized below: Unit*2 Numer of switches 1992 1993 1994 found outside required values Total Failed to Total Failed to Total Failed to OOT actuate OOT actuate OOT actuate TS (*55 to *59) 4 0 14 5 I 0 I 0 UFSAR design (<+48) 0 0 3 1 0 0 test limits (44-48) Unit 3 Numer of switches found outside 1992 1993 1994 required values Total Failed to Total Failed to Total Failed to OOT actuate OOT actuate OOT actuate TS ( *55 to *59) I 8 I 2 I 7 0 1 1 UFSAR design (<+48) 1 0 5 -0 0 0 test limits (44-48) I As shown above, in 1993, the instruments were found outside TS and UFSAR tolerances on 29 occasions. Seventeen of the 1993 events occurred on Unit 2 after instrument replacements. Details of the 1993 failures*are listed in Attachments 1 and 2. c. Safety Significance: The ~outine drift.and failures of the level instruments was significant. Between June and December 1993 instrument mechanics performed seven surveillances on the ten Unit 2 switches. This corresponded to a total of seventy individual switch challenges. Of the 70 challenges, the switches failed to actuate six times and 12
were found outside the expected manufacturer drift twice. This ~quated to a potential individual failure rate greater than 10% for Unit 2. The actuation logic was operable because in each event only one switch in the trip logic was found inoperable. However, in January 1993 the Unit 3 low pressure coolant injection (LPCI) initiation would have been delayed since* the as-found settings of two switches were found non-conservatively out-of- tolerance. The design requirements for ECCS systems were defined in 10 CFR. 50.46 and described in the UFSAR. The automatic initiation ~nd isolation function actuated by the level switches were assumed in the UFSAR in the following accident scenarios: . - 1. Section 15.6.5. Loss of coolant accidents resulting from piping breaks inside containment: ECCS was assumed to automatically actuate on either low-low water level or high drywell pressure.
2. Section 15.2.7. Loss of normal feedwater flow: HPCI initiated at low-low level setpoint, (The analysis determined that without HPCI makeup level would remain five feet above core.) 3. Section 15.6.1. Inadvertent opening of a safety/relief
- valve: During a concurrent loss of offsite power,* HPCI
automatically actuated on low-low level. 4. Section 15.5.1. Inadvertent initiation of HPCI: vessel .level increases until HPCI pump turbine was tripped by hi level signals. The inspectors queried the licensee regarding the impact of the instrument performance on the Individual Plant Evaluation (IPE). The licensee determined the failure rate for 1992 and 1993 to be 10~ per hour, whereas the failure rate assumed in the IPE was 5xl0~ per hou~. Level switch failures affected the assumed failure rate of the common actuation system (CAS) in the IPE. The CAS consisted of the low-low reactor water level and high drywell pressure initiation logic. The level switch logic dominated the CAS failure sequence. The baseline IPE has a core damage
- frequency (COF) of l.85xl0-5/year. The bounding case for level
switch failures (failure of CAS) resulted in a CDF of 4.35xl0-5/year, an increase of 135 percent. In January 1993, the as-found settings of two switches affected the LPCI actuation logic and would have initiated late. The . licensee determined that assuming this condition existed for 10 days during the reactor years of operation, this event increased the COF by 1 percent. 13
d. Inadequate Long Term Corrective Actions The licensee documented the instrument out-of-tolerances in numerous deviation reports (DVR) and PIF~. In 1989 a feasibility study was initiated tq review possible design changes to improve equipment performance. *The study was completed in January 1991; however, no actions were taken with respect to the these instruments. A DVR written in mid-1991 referenced another feasibility study. The inspectors queried the licensee regarding the status of that study; however, it appeared the study had not been completed. Licensee Event Report 237/93001 stated a feasibility study was initiated to review possible design change; however, it was not known whether that was a new effort or a reference to the 1991 study. After the inspectors identified the 1993 adverse trend, the licensee initiated a new engineering study, documented in LER 237/93031. Discussions with the site engineering operations support supervisor indicated that during 1993 site engineering was working on a resolution to the drift problems; however, the site engineering actions were isolated from the station engineering organization. In addition, the magnitude of the problem was not known until a detailed operability evaluation was performed after the inspectors questioned the adverse trend.
Although some action was initiated by the licensee to resolve the long term equipment reliability problem, the licensee failed to initiate actions commensurate to the safety significance .. Also in 1989, the licensee initiated a TS change to Table 3.2.1 as part of the TS improvement program. Due to other TS changes and the TS upgrade program, this particular TS change request was not submitted to the NRC until March 1993. Since the licensee was unaware of the significance of the adverse trend, the TS amendment was not given a high priority. e. Failure to Perform Root Cause Determinations During the March 1993 Unit 2 outage, the licensee replaced the instruments with new like-for-like instruments. The inspectors reviewed the maintenance work package and had several concerns regarding the instrument quality and resolution of problems identified during installation. Specifically: 1. The instrument technicians identified several manufacturing flaws such as incorract pipe nipple lengths and cold soldering flaws with the newly purchased instruments. These concerns were corrected prior to installation. 2. Two instruments (2-263-728 and ._72D) r~quired replacement of spiral wells. The spiral wells were essential to proper equipment operation. 14
l I.
3 . Instrument 2-263-72A required a replacement of the magnetic. hub assembly and mercury switch associated with contact 7-8. The root cause of the switch problem was not evaluated . . This contact failed to actuate during its first three surveillance tests following installation. . . 4. Instrument 2-263-72C required a replacement of the mercury switch associated with contact 5-6 due to excessive drifting problems during bench testing. The cause of the drift was . not investigated. This contact drifted outside TS limits in seven of eight surveillances in 1993 following installation. 5. The receipt inspection and testing.consisted of actuating the switches once and did not challenge the repeatability of testing results. The receipt inspection did not identify the manufacturing problems stated above.
The licensee did not determine the root causes to the above problems encountered during installation. As a result, it appeared that identical problems occurred during the routine surveillances after installation. The inspectors reviewed operator log books, maintenance work .requests, completed monthly surveillances and integrated reporting program documents to determine how problems identified during the surveillances were addressed. The inspectors also interviewed several instrument technicians and witnessed two monthly surveillances. The inspectors observed that few root cause determinations were made for failures during routine surveillances. Specifically: 1. * The instrument mechanics routinely attempted to adjust or replace switches when the as-found readings were outside TS limits. The replaced switches were not retained for further investigation. These actions prevented the licensee frQm determining if the switches were faulty or mispositioned in tne switch holder. 2.. PIFs and lev~l IV investigations were initiated for most of the events listed in Attachment 1 and 2. The cause codes listed in these documents included component aging, setpoint drift, and comments on instrument accuracies. The licensee did not perform root cause determinationsfor identified out-of-tolerances during surveillance testing. f. Failure to Identify Significance of Adverse Trend and Individµal Equipment Performance Instrument maintenance personnel tracked instrument performance on individual graphs depicting as-found and as-left data for each month. Problem identification forms (PIFs) were written for as- 15
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9. h. The licensee conducted a probabilistic risk assessment as discussed in paragraph 8.c. The licensee concluded the instruments were operable based on the assessment results and the most recent surveillances where no instruments were found out-of- tolerance. Site engineering initiated several compensatory actions to ensure operability until long term corrective actions were completed. These actions included developing inspection criteria, predictive trending, identifying acceptable performance criteria and actions if outside this guidance, and establishing a
- new tolerance band following TS amendment approval.
Summary The reactor water level instruments have been a long-standing problem at Dresden. The licensee initiated activities to resolve the issue; however, the pace of these actions was not commensurate with the safety significance of the problem. The significance of the adverse trend on Unit 2 was not identified by the licensee. Although PIFs were written, the general adverse trend and indivi~ual performance trends were not identified. Root causes of the instrument drifts and failures were not determined. Failure to promptly identify, determine root cause, and correct recurring reactor water level switch problems .is contrary to 10 CFR 50, Appendix B, Criterion XVI and is considered an Apparent Violation (50-237/94002-04(DRP)). One apparent violation for inadequate corrective actions was identified . Licensee Actions on Previous Inspection Findings {92701, and 92702) {Closed) Unresolved Item (50-237/93034-02CDRPll: Review of corrective actions for recurring reactor water level instrument drifts. This item is discussed above in paragraph 8. The subject of corrective actions for recurring instrument drifts was identified as an Apparent Violation in this report and this tracking item is closed. (Closed) Unresolved Item C50-237/93034-03CDRPll: Recurring reactor water level instrument drifts not reported. This item is discussed above in paragraph 5.a. The subject of reporting repetitive drift problems was identified a Violation in this report and this tracking item is closed.* {Closed) Inspector Follow-up Item {50-237/93017-0lCDRPll: Small fires caused by heat treatment operations. The inspectors reviewed the li£ensee's corrective action, which consisted of tailgate training of the events, and found the actions appropriate. This item is closed. 17
Temporary Instruction 2515/065: TMI Action Plan Requirement Follow-up The inspectors qbserved various portions of the installation and testing and verified operability of the Unit 2 reactor vessel water level indication system (RVLIS). *This item is closed for Unit 2. The licensee* intends to install RVLIS on Unit 3 during t~e March 1994 refueling outage. This item remains open for Unit 3. . One previously unresolved item was identified as a Violation in this report and is discussed in paragraph 5.a. One previously unresolved item was identified as an Apparent Violation in this report and is discussed in paragraph 8. 10. Licensee Event Reports CLERsl Follow-up {92700) Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with technical specifications. Unit 2 {Closed) LER 237/93030. Revision 0: Station Procedure for Containment Purging Allow Venting Through the Reactor*B~ilding Ventilation System. This event.was the subject of Unresolved Item 50-237/93034-01. This LER is closed. (Closed) LER 237/93031. Revision 0: Reactor Vessel Level Instrumentation Found Outside of Technical Specification Due to Instrument Drift. This event is discussed in paragraph 8; the quality of this LER is discussed in paragraph S.b. This LER is closed. Unit 3 (Closed) LER 249/93001. Revision 1: Emergency Core Cooling Level Indicating Switch Out of Calibration due to Instrument Drift. This revision discussed new corrective actions resulting from increased instrument failures. This event was identified as an Apparent Violation in this report and this tracking items is closed. (Closed) LER 249/94003. Revision O: Unit 3 Reactor Vessel Level Instrumentation Found Outside of Technical Specification Limits Due to Setpoint Drift. The 263-728 contacts 7-8 failed to actuate during a routine surveillance. The inspect-Ors disagreed with the stated cause of instrument drift. The instrument failed to actuate completely due to an equipment problem, not traditional setpoint drift. The subject of r.oot causes for failed instrumentation was identified as an Apparent . Violation in this report and this tracking item is closed. No violations or deviations were identified. 18.
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Attachment 1: UNIT 2 Emergency Cooling System Reactor Water Level Switches REQUIRED PROBLEM - AS FOUND LEVEL (F)AILURE CONTACT INITIATION LEVEL (TS/FSAR) (D)RIFT NOTES INSTRUMENT SWITCH LOGIC DATE (INCHES) (See #1) (See #2) 263-72A 7-8 CS, ADS and DG 06/11/93 ( '.""88. 6) -59 (TS) F B logic was operable and would wouldn't trip have initiated ECCS. 07/12/93 didn't trip F B logic was operable and would have initiated ECCS. 08/09/93 didn't trip F B logic was operable and would have foitiated ECCS. 263-728 3-4
- HPCI ISOLATION
08/10/93 42.9' +48 D 09/03/93 27.6 (FSAR) F 10/01/93 didn't trip F Operator action necessary to isolate HPCI on hi level 5-6 LPCI 07/15/93 didn't trip -59 (TS) F A logic was operable and would have initiated ECCS. 263-72C 5-6 LPCI and HPCI 06/11/93 -60.8 -59 (TS) D 07/19/93 -60.4 D 09/03/93 (-68.4) ' F As found setpoint was may not have approximately equal to the elevation of variable leg sensing tripped tap. 10/01/93 -62.5 D 10/29/93 -52.3
Conservative setting 11/23/93 -65.5 .F 12/22/93 -52.8
Conservative setting 7-8 CS, ADS and DG 10/01/93 -62.5 -59 (TS) D . 10/29/93 -52.5
Conservative setting 11/23/93 -62.9 D ,
,, . Attachment 2: S stem Reactor Water Level Switches . REQUIRED PROBLEM AS FOUND LEVEL (F)AILURE CONTACT INITIATION LEVEL (TS/FSAR) (D) RIFT INSTRUMENT (SWITCH) LOGIC DATE
- (INCHES)
(See #1) (See #2) NOTES 263-72A 3-4
- HPCI ISOLATION
01/28/93 44.2 +48 (FSAR) D 5-6 LPCI and HPCI 01/13/93 -59.9 -59 (TS). D ECCS initiation de.layed (both A & B logic OOT.) 7-8 CS, ADS and DG 01/13/93 -59.9 -59 (TS) D 263-728 3~4
- HPCI. ISOLATION
01/28/93 41.4 +48 (FSAR) D 02/25/93 50.5 D' 04/21/93 44.2 D 5-6 LPCI 01/13/93 -59.7 -59 (TS) D ECCS initiation delayed (A & B logic OOT) 02/25/93 -59.9 D 7-8 CS, ADS and DG 06/16/93 -61.3 -59 (TS) D 07/14/93 -65.4 F 08/16/93 -66.9 F 01/19/94 didn't trip F A logic was operable and .would have initiated ECCS NOTES 1. * The technical specification limit is +84 inches above the top of active fuel which corresponds to -59 inches on the Instrument range. 2. DRIFT is defined as+/- 6.6 inches from ideal setpoint (-57 or +46 inches). A FAILURE is considered any setpoint outside this drift band or a failure to actuate.
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