IR 05000315/1990022
| ML17328A788 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 11/16/1990 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A786 | List: |
| References | |
| 50-315-90-22, 50-316-90-22, NUDOCS 9011270070 | |
| Download: ML17328A788 (71) | |
Text
U.
S.
NUCL'EAR REGULATORYr COMMISSION
REGION III
Report Nos.
50-315/90022(DRP);
50-316/90022(DRP)
Docket Nos.
50-315; 50-316 License Nos.
American Electric Power Service Corporation Indiana Michigan Power Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, MI Inspection Conducted:
August 29 through October 9, 1990 Inspectors:
J.
A. Isom D.
G.
Passehl CP;.&
Approved BSrj.,B.
L. Burgess, Chief Projects Section 2A Ins ection Summar DATE //-/8-ic Ins ection on Au ust 29 throu h October
1990 Re ort Nos.
50-315/90022 DRP '0-316/90022 DRP of: plant operations; ESF actuations; maintenance; surveillance; fire protection; emergency preparedness; safety assessment/quality verification; and, Bulletins, Notices and Generic Letters.
Results:
Of the eight areas inspected, no violations or. deviations were identified in 'seven areas.
One violation was identified with three examples (failure to implement a procedure, Paragraph 4.a; failure to have a procedure, Paragraph 4.b; and use of an unapproved procedure while working on safety-related equipment Paragraph 4.b) in the remaining one area.
One new open item was identified (and is discussed in Paragraph S.f) in the following inspection area:
Surveillance.
Plant 0 erations:
During this reporting period, with the exception of the reactor transient caused by closure of one of the main steam stop valves during a surveillance, Unit 1 operated at 100 percent with no major operational problems or equipment malfunctions.
On September 26, 1990, the licensee commenced slow power reduction on Unit 1 for a refueling outage scheduled to begin on October 20, 1990.
CL I "70(,)70 cjc) 1 l 1 g fqOOCK O~~Pgow g ~
0
Unit 2 remained in MODE 6 for most of the reporting period.
The unit was placed in half-loop condition 'from September 24 - 29 in order to repair leaking pressure isolation check valves.
Additionally, Unit 2 received an Engineered Safety Features (ESF) actuation when a hi-hi steam generator water level (SGWL) signal was received during a startup surveillance test.
Maintenance:
Inspectors observed or reviewed maintenance job orders associated with five maintenance activities.
These activities involved repacking of a safety injection pump; replacement of a diaphragm on a power operated relief valve; repair of containment ventilation valves; repairs to leaking pressure isolation check valves; and divider barrier seal replacement for Unit 2.
Inspectors issued one violation with three examples.
The first example concerned the failure by the maintenance technicians to follow a procedure when repacking the safety injection pump.
The second and third examples concerned maintenance activities associated with two similar valves in which a procedure was not used to perform the maintenance on a power-operated relief valve (PORV) and an unanproved procedure was used to perform maintenance on the other PORV.
Surveillance:
Inspectors observed or reviewed six surveillances.
The procedures reviewed were, in general, well-written and appeared that they could be accomplished by operators or technicians with proper training.
Although. some pi ocedural enhancements were found, inspectors found no discrepancies which would have prevented the procedures from being accomplished.
The'inspectors did have questions with the 10 gallons per minute (gpm) leakage acceptance criteria used in the licensee's surveillance procedure for some pressure isolation check valves.
The inspectors made this observation into an open item until the licensee has provided adequate basis for the
gpm leakage rate associated with these check valves.
,
Persons Contacted DETAILS
"A. Blind, Plant Manager
- J. Rutkowski, Assistant Plant Manager - Technical Support L. Gibson,'ssistant Plant Manager - Projects
"K. Baker, Assistant Plant Manager - Production B. Svensson, Executive Staff Assistant J.
Sampson, Operations Superintendent
~P.,Carteaux, Safety and Assessment Superintendent T. Bei lman, Maintenance Superintendent J. Droste, Technical Superintendent-Engineering
"T. Postlewait, Design Changes Superintendent
"L. Matthias, Administrative Superintendent
- J. Mojcik, Technical Superintendent Physical Sciences M. Horvath, guality Assurance Supervisor D. Loope, Radiation Protection Supervisor The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
"Denotes some of the personnel attending the Management Interview on October 12, 1990.
0 er ati ona1 Sa fet Verification 71707 71710 42700 Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant startup, steady power operation, plant shutdown, and system(s)
lineup and operation were observed as applicable.
The performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
The Plant Manager, Assistant Plant Manager-Production, and the Operations Superintendent were well-informed on the overall status of the plant, made frequent visits to the control rooms, and regularly toured the plant.
Evaluation, corrective action, and response to off-normal conditions or events, if any, were examined.
This included compliance with any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
(
I,
Unit 1 operated at 100-percent pated thermal power until September 8,
1990, when power was reduced to 46-percent when the No.
14 Steam Generator Main Steam Stop Valve started to drift closed during routine surveillance testing (see Paragraph S.c).
The stop valve was repaired and the unit was returned,to 100-percent power on September.
10, 1990.
To conserve fuel, a gradual coast down to 70-percent power commenced on September 26, 1990 in order to begin the unit's upcoming refueling outage on schedule.
The unit exited the inspection period at 77-percent power.
b.
Unit 2 entered the inspection period in MODE 6 with the reactor core unloaded, continuing with the refueling outage which began June 29, 1990.
Fuel loading commenced on September 2,
1990, and was completed September 4,
1990.
The unit entered MODE 5 on September 14, 1990.
The Reactor Coolant System was drained to reduced inventory on September 24, 1990, to repair a vibration problem on No.
23 Reactor Coolant Pump and to repair leakage problems on two pressure isolation valves.
The reduced inventory condition was terminated September 29, 1990.
The half loop level modification had been completed just prior to draining to the reduc'ed inventory.
The unit entered MODE 4 on October 6,
1990.
The unit exited the inspection period in MODE 3, which was reached October 8, 1990.
C.
As a result of eddy current testing of the Unit 2 incore flux monitoring thimble tubes during the Unit 2 outage, the licensee detected significant wear with 25 of the 58 total thimble tubes.
As a result, the inspectors were informed that the 10 thimble tubes which showed greater than 50-percent through-wall reduction were replaced during this outage and 19 other thimble tubes were repositioned.
No violations, deviations, unresolved or open items were identified.
3.
ESF Actuations 93702 On October 7, 1990, Unit 2 was in MODE 4 and the licensee performed valve stroke t'esting on 2-FMO-202 (main feed to Steam Generator No.
isolation valve) to satisfy startup surveillance test requirements when an inadvertent Engineered Safety Features actuation occurred.
A Steam Generator'No.
22 hi-hi level signal was generated (setpoint=67-percent)
causing a feedwater isolation and turbine trip, Prior to the test, steam generator level was 65 percent.
After cycling the valve the hi-hi -alarm was received.
The cause was attributed to leakby of the associated feedwater regulating valve (closed).
A work order was requested to fix the leakby; No equipment changed position since all feedwater isolation valves were already closed and the turbine had been tripped since the outage started.
No violations, deviations, unresolved or open items were identified.
~
'
l
4.
Maintenance 62703 42700 Maintenance activities in the plant were routinely inspected, including both corrective maintenance (repairs)
and preventive maintenance.
Mechanical, electrical, and instrument and control group maintenance activities were included as available.
The focus of the inspection was to assure the maintenance activities reviewed were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specifications.
The following items were considered during this review: the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The following activities were inspected:
During the current Unit 2 refueling outage, planned maintenance was performed on the No.
2 North Safety Injection Pump which included replacement of the rotating assembly, bearings, gaskets, and mechanical seals.
The work was documented in Job Order 8016574, which included use of Procedure No. "~12 MHP 5021.008.001,
"Safety Injection Pump Disassembly, Repair, and Reassembly (Rev. 4)."
Complete reassembly was delayed because of a lack of packing rings available onsite.
The craft assigned the pump job did not complete the entire job, and to facilitate outage progress, were moved to perform maintenance on other pumps.
New packing rings were ordered on August 1, 1990.
Subsequent to the arrival of the packing rings, the remaining seal installation was completed (incorrectly only one seal ring was installed vs. the required three)
on or about August 16, 1990 by a maintenance mechanic not part of the crew originally assigned the pump job.
Upon placing the pump back into the system, leakage through the seal became evident, and as stated in the job order (No.
8015313)
was "....enough that seal areas had to be wrapped to prevent spray on walls."
The inspector conducted an investigation which included interviews with several personnel involved with'he work.
The investigation led to a maintenance mechanic involved with the incorrect seal assembly installation.
Because the initial discussion with the maintenance mechanic regarding the work he had accomplished on the SI pump was not consistent with the procedure steps used for the work activity, the inspector performed a follow-up interview with the individual.
After further discussion, it was revealed by the mechanic that he did not follow the procedure steps when finishing the reassembly.
Although the mechanic stated. that he reviewed the procedure prior to the job, he had only used Attachment 2 (a schematic of the seal assembly)
of the procedure to perform the task.
Unit 2 Technical Specification 6.8. 1 requires that written procedures be implemented covering items recommended in Appendix A of Regulatory Guide 1.33, November 1972, which includes (at Section I. 1),
procedures for performing maintenance which can affect the performance of safety-related equipment.
'ailure to implement written procedures while performing maintenance which can affect the performance of safety-related equipment is considered a violation of Technical Specification 6.8. 1 ( Yiolati on 50-316/90022-01A)
.
Other factors which may have contributed to the this event included:
(1)
There were insufficient packing rings to complete the job initially.
(2)
The (attachment 2) drawing showed two packing rings while the number required in the table at the bottom of the drawing indicated three.
(3)
The procedure test referred to a "seal ring" while that same part was labelled a "seal ring shaft sleeve" in attachment 2.
(4)
The number of packing rings installed was not in agreement with the number required by either the attachment 2 drawing or the table.
Although this fact was identified. by the maintenance mechanic to his supervisor, the supervisor believed that only one packing ring was sufficient.
There was no direct safety significance as a result of this event as the work was performed at a time when the associated Action Statement did not apply.
There was, however, possibi lsty for a personnel contamination incident should the pump have been started with individuals in the area.
The licensee's corrective actions included correcting the procedure deficiencies.
A note was added to the drawing saying it was for general assembly only.
The procedure text was revised to state that three packing rings are required.
A management directive was issued to stress again the importance of following procedures.
The resident inspector's review of the maintenance job order package for repair of 2-NRV-152 (Pressurizer Train "B" Pressure Relief Valve), found that the licensee had performed work on safety-related equipment without an approved procedure.
Additionally, the inspector found that, during the current Unit 2 refueling outage, licensee had performed diaphragm replacements on another PORV, 2-NRV-153, on one occasion without a procedure and on a second occasion with an unapproved procedure.
While touring Unit 2 containment, the Resident Inspector observed maintenance being performed on the air actuator diaphragm associated with NRV-152.
Although the maintenance mechanics performing the activity appeared to be knowledgeable, the inspector was informed by the mechanic in charge of the repair that they did not have any procedure for performing the repair.
When
\\(
asked why the valve was being repaired, the inspector was informed that there were problems with air leaking by the stem and the diaphragm.
Because the maintenance work was being performed on the pressurizer power-operated relief valve (PORV), the inspector reviewed the maintenance work package to determine whether a
procedure was required.
The inspector's review of the job order and discussions with the licensee's maintenance staff found that the maintenance staff had used a "Repair Plan for Masoneillan Air Actuator Diaphragm and Installation" to perform corrective maintenance on NRV-152.
The inspector was informed by the licensee's staff that use of the repair plan was appropriate for the task and was in accordance with the licensee's Plant Manager Instruction (PMI) 2290 titled "Job Order."
Although the inspector's review of PMI-2290 indicated that written maintenance plan approved by the job planners or supervisor could be used to enhance those activities which were normally within the skills of a qualified maintenance personnel, the inspector found that Section 4.3.6 of PMI-2290 required
"maintenance which can affect the performance of safety-related equipment shall be properly pre-planned and performed in accordance with approved written procedures" and prohibited substitution of a maintenance plan for a procedures.
The inspector understood that phrase
"Repair Plan" and
"Maintenance Plan" were equivalent.
Because the inspector's review of the "Repair Plan For Masoneillan Air Actuator Diaphragm and Installation,",
and problem report associated
~ith another PORV indicated that air actuator diaphragm installation was a maintenance activity outside the ski lis of many qualified maintenance personnel, the inspector determined that a procedure was appropriate for this maintenance activity.
I Inspector's review of the "Repair Plan For Masoneillan Air Actuator Diaphragm and Installation" for 2-NRV-152, found that this repair plan was structured like a procedure.
It contained 5 sections titled:
Objectives; Initial Conditions; Precautions; Disassembly; and Installation.
Additionally, the inspector found the procedure to be detailed and specified step-by-step instructions.
The disassembly and installation sections contained 9 and 13 steps respectively and specified the proper disassembly and installation of approximately
different actuator components.
Additionally, because of problem report 90-1327, which discussed slow ISI stroke times associated with 2-NRV-153, inspector reviewed job packages associated with this PORV.
The inspector found that the licensee had performed two diaphragm replacements during this outage on 2-NRV-153.
The initial diaphragm replacement was necessary because the. 2-NRV-153 failed its ISI stroke time.
The inspector's review of this job order package found that the first diaphragm replacement was accomplished without a procedure and it was only partially successful.
Failure to have written procedures for the performance of maintenance which can effect the performance of safety-related equipment is considered a violation of Technical Specification 6.8. 1 (Violation 50-316/90022-018).
Consequently, the licensee performed a second diaphragm replacement using the repair
plan written for diaphragm installation for 2-NRV-152.
The inspector noted that the second diaphragm replacement was successi'ul and that 2-NRV-153 stroke time was reduced to values allowed by the ISI program.
The inspector noted the following with regard to maintenance activities associated with valve 2-NRV-153:
First, the licensee's problem report 90-1327 stated that slow stroke time associated with 2-NRV-153 was because of diaphragm leakage caused by improperly installed actuator assembly.
The problem report
'tated that "when disassembled, washers required to be put on either side of the diaphragm were found installed on the bottom.
When stroked, this allowed the diaphragm to contact sharp edges of the stem and be cut."
Also, the problem report appeared to attribute the disassembly and reassembly of the actuators by different individuals to be a contributor to the improper actuator assembly.
It also noted that no procedure had been written for diaphragm installation.
Secondly, the inspector's review of job order packages indicated that whenever the licensee used the repair plan, they were able to successfully complete the diaphragm replacement.
The inspector's discussions with the maintenance staff indicated that, in the past, power operated relief valve diaphragm replacement was considered within the skill of the craft and that this maintenance activity had been accomplished successfully on numerous occasions with no procedure.
However, because of diaphragm reassembly problems found with another PORV, NRV-153, the maintenance department decided to write a repair plan to ensure repairs were performed properly on NRV-152.
Inspectors were informed that, although the need for a procedure instead of a repair plan was considered by the maintenance staff, they determined that because of their past success at repair of these valves without a procedure, repair plan was more appropriate for this maintenance activity than a procedure.
Failure to have written procedures for the performance of maintenance which can affect the performance of safety-related equipment that are reviewed by the Plant Nuclear Safety Review Committee (PNSRC)
and approved by the Plant Manager is considered a violation of Technical Specification 6.8.2 (Violation 50-316/90022-01C).
At the NRC exit meeting on October 12, 1990, D.
C.
Cook management agreed to review the plant's use of repair plans to determine if any corrective actions were warranted.
The licensee completed replacement of the divider barrier seal made of Uniroyal 3807 in Unit 2 containment with Uniroyal 41300. Divider bar rier seals for both Units were declared inoperable on August 1, 1990, because cracks in the Unit 2 seal were found during the performance of "Containment Divider Barrier Seal Inspection,"
OHP 4030 STP.249 (see Inspection Report 50-'315/90021(DRP);
50-316/90021(DRP) ).
The licensee plans to replace divider barrier seal material made of Uniroyal 3807 in Unit 1 during the upcoming refueling outage in October 1990 '
The divider barrier seal is a flexible barrier located between the bottom of the ice condenser compartment and the containment cylinder wall to prevent the flow of steam and air from bypassing the ice condenser.
The seal assembly is made of a flexible barrier and a
steel plate which is bolted to the containment structure.
The seal material was designed to withstand a peak pressure of 24 pounds per square inch and was expected to have a minimum life under operating conditions of greater. than 10 years.
As a result of the surveillance test performed on the RCS Pressure Isolation Valves discussed in Paragraph 5.f, the inspector reviewed the work packages associated with the two check valves identified to be leaking greater than their allowable values.
No problems were noted.
The two (of 22 total) problem valves were 2-SI-170-L3 (Accumulator Tank No.
3 Outlet and ECCS to RCS Loop 3 Cold Leg) and 2-SI-158-L2 (West RHR and North SI to RCS Loop 2 Hot Leg).
The corrected leakages (for temperature and pressure)
were reported as 3.04 gpm for SI-170 and "unquantifiable" for SI-158.
Acceptable leakage is
gpm and 10 gpm, respectively (See Paragraph 5.f).
The work packages for both check valves were well documented.
The description of work done was well explained.
Non-destructive examinations performed were complete and also well documented.
All hold points were observed.
To repair the valves, SI-170-L3 had its internal seat and disc polished and SI-158-L2 had its internal seat lapped and the disc replaced.
Both valves were retested and exhibited zero leakage.
The resident inspectors reviewed maintenance procedure
"GH Bettis Air Actuator Overhaul," "*12 NHP 5021.001.093, and interviewed various licensee personnel to determine the cause of the failures associated with some of the containment purge valves.
The inspectors'eview of the maintenance procedure used to overhaul the valve found the procedure to be generally well-written and appeared to be consistent with the vendor's instruction for disassembly and reassembly for the
.GH Bettis actuators.
On September 6, 1990, the licensee found that two upper containment purge valves which had satisfactorily passed their initial operability test failed to close as required during the subsequent performances of the containment ventilation isolation (CIV) signal test.
The licensee's investigation attributed the containment purge valve failures to actuator-to-valve stem alignment difficulties during installation of the actuator to the valve.
This alignment problem caused excessive wear on the scotch-yoke bushing which resulted in valve failure.
The licensee's investigation found that because of the weight of these actuators when fully assembled (approximate weight ranged from 1295 to 1672 lbs. depending on model type), installation of the actuator to the valve was difficult to accomplish with the rigging
I ri
equipment.
The licensee's investigation indicated that the dama'ge to the scotch-yoke oushing probably occurred when the actuator was installed onto the. stem.
Because of the weight of the actuator on the stem, as the actuator was being slipped over the stem, there may have been excessive forces being felt on the scotch-yoke bushing surface.
To prevent reoccurrence of this type of problem in the future, the licensee planned to write another overhaul procedure for the actuators which would remove the spring cartridge assembly and reduce the weight of the actuator.
Additionally, the installation process was complicated by the fact that the actuator assembly, once it had been slipped onto the valve stem, had to be rotated approximately 5 degrees in order to align the bolt holes which secured the actuator assembly to the valve body.
The licensee's investigation revealed that'he 5 degree offset associated with the actuator assembly was necessary to ensure proper seating of the valve disc against its seat.
Without this offset, the scotch-yoke could not r'otate the full 45 degrees (approximately) without hitting the internal section of the actuator assembly and the full seating torque was not being applied to the valve seat by the disc.
The licensee subsequently modified the stem"adapter (part of the scotch-yoke assembly).
Although the licensee initially believed that there may be potential problems with all 10:of the 14 Unit 2 containment ventilation valves wnich were overhauled during this outage, their investigation indicated that only three of the 10 valves were susceptible to actuator-to-valve alignment problems.
These valves were VCR-103, 106, and 206, which were the GH Bettis air actuators of the 820 series which were installed vertically.
These three valves were repaired.
One violation was identified.
No deviations, unresolved or open items were identified.
5.
Surveillance 61726 42700 The inspector reviewed Technical Specifications required surveillance testing as described below and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were properly accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following activities were inspected:
a.
"*1 IHP 4030 STP.015 (Rev.7),
"Steam Generator Mater Level Protection Set II Surveillance (Monthly)."
The test demonstrated operability of selected reactor trip instruments for steam generator water level, steam/teed flow mismatch, and operability of engineered safety feature instruments for the main turbine and auxiliary
I'
feedwater pumps.
The operability of the instruments was verified by simulating an actual steam, generator lo-lo level reactor trip signal, for example, and measuring the corresponding voltage at which the signal was initiated.
The technicians performing the procedure appeared knowledgeable and read each step aloud before performing the required action.
Proper phone communication was established between the technician at the instrument racks behind the control room panel and the technician in front of the panel to acknowledge alarms generated during the test.
There were no procedural or personnel probl'ems noted during this test.
All "as-found" data met the acceptance criterion.
""12 THP 4030 STP.208 BI (Rev. 1),
"ECCS Flow Balance Injection System."
The purpose of the surveillance was to verify balanced flow through the system, by measuring individual loop injection flow and by measuring charging pump discharge resistance, as required by the Technical Specifications; The test was observed for the Unit 2 West Centrifugal Charging Pump.
Test results showed the pump met all acceptance criteria for loop flows and pump discharge resistance.
The procedure was generally satisfactory.
The sign-off steps were not separate from the body of the procedure, and valve line-ups were included in the appendices and required independent verification.
A problem was observed, however, at Step 5.2.6, which established flow through the, Boron Injection Tank by opening BIT inlet and outlet valves.
Once these valves were opened, BIT flow wasn'
indicated since the downstream valves (INQ-51 through 54, individual loop injection valves) were not in their test (open) position as called for in the valve line-up sheet.
Once this was identified, the loop injection valves were opened and BIT flow was established.
The problem stemmed from the multiple activities ongoing in the control room at the time.
The lead test engineer gave Operations Department personnel the, line-up sheet for the test the previous night.
Since a fill and vent of the BIT had just been scheduled, the Shift Supervisor wanted to keep the portion of the system isolated from the reactor coolant system until the test 'actually started.
When the test did start, however, the four valve positions were overlooked.
The significance of the problem was minimal since the charging pumps are started with their discharge valves shut and on miniflow.
The result was that one extra set of isolation valves had to be opened
"to established BIT system flow.
To prevent future occurrence of the problem, a procedure change was implemented to verify with Shift, Assistant Shift, and Unit Supervisor signatures that the entire valve line-up sheet be independently reviewed and verified prior to test performance.
On September 8,
1990, a main steam valve 'drifted to approximately the 26-percent open position during the performance of "Steam Generator
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Stop Valve Dump Val ve Survei1 lance Test",
procedure 1-OHP 4030 STP.018.
The inspectors reviewed the procedure to understand the sequence of events which led to this transient.
The inspectors'eview found that, in general, the procedure was well-written, satisfied its objectives and appeared to have been performed correctly.
However, the inspectors did note that although the drift of the steam generator stop valve from its open detent was anticipated, the procedure did not require verification of the proper operation of the hydraulic system used to restore the stop valves to their normally full open positions The hydraulic system used to open the stop valves consists of an oil header tank, a hydraulic pump and a
three position solenoid valve used to direct flow to the double ended cylinder.
On September 8,
1990, because of obstructions to the hydraulic pump motor, the operators were not able to reopen the stop valves which had drifted closed during the course of the surveillance and were forced to reduce power to 46-percent in order to prevent violation of thermal limits.
The residents were informed by the licensee that the surveillance procedure will be reviewed to determine whether verification of the proper operation of the hydraulic system before performing the surveillance could be accomplished.
The procedure is performed monthly and is used to demonstrate the operability of the steam generator stop valve dump valves which, when opened, vent the high pressure air normally used to maintain the stop valves in their fully opened position.
When one of the two dump valves is opened, the differential pressure between the main steam and the ambient pressure will create the closing force for the stop valves.
The steam generator stop valve dump valve system is designed such that a three way valve and two dump valves ensure that the stop valves could be closed in an emergency even with a failure of one of the two dump valves.
The hydraulic system is used to open the valve.
The inspector observed the licensee's monthly surveillance testing of their turbine-driven auxiliary feedwater pump on Unit 1 and reviewed procedure,
- "1-OHP 4030 STP.017T,
"Turbine Driven Auxiliary Feedwater System Test,"
used to perform this test.
The inspector observed that the technicians performing the test appeared to be conscientious, and knowledgeable of the surveillance and all as-found data were within the required specifications.
Additionally, the inspector's review of the surveillance procedure found no major discrepancies and it appeared to the inspector that the procedure satisfactorily demonstrated the operability of the Unit 1 turbine driven auxiliary feedwater pump as required by the Technical Specification.
Because of the personnel contamination and radiological event which occurred during relief valve testing on July 21, 1990, (See Inspection Report 50-315/90020(DRSS);
50-316/90020(DRSS)),
the resident inspectors reviewed the'icensee's procedure
MHP 5021.001.034,
"Safety Valve Setpoint Verification by Bench Test."
The inspectors found that the licensee had used two procedures:
"Safety Valve Setpoint Ve~ification by Bench Test,"
and "Model RV005
0
'Operation, Installation and Maintenance Manual," (vendor's operating instructions for the test equipment)
on July 21, 1990.
The review of these procedures indicated that proper use of these procedures appeared to ensure the verification of the safety valve setpoints and that the testing configuration used on July 2l.,
1990 appeared to have properly verified the correct lift setpoint for the'elief valve.
Although the inspectors did not find any technical deficiencies with those procedures, they noted the following:
The licensee's test configuration appeared to be slightly different than what was shown in Figure 2 of the procedure,
"Safety Valve Setpoint Verification by Bench Test" in that a
much more sophisticated testing apparatus, RV005, was used instead of a nitrogen bottle or compressed air and test gauge arrangement.
Test procedure
"Safety Valve Setpoint Verification by Bench Test" did not reference the use of "Model RV005 Operation, Installation and Maintenance Manual," although the inspectors'nterviews with the technician indicated that both procedures were used.'he
"Model RV005 Operation, Installation and'aintenance Manual" which contained detailed instructions on the proper use of this test equipment was not approved for use at the plant at time of test on July 21, 1990.
RV005, manufactured by Dunn's valve Testers, Inc., is used by the licensee to test their relief valves.
There are approximately
gauges and 10 valves located on the test equipment which could be used to test various relief valves.
The operation section of the procedure contained instructions to test different size flanged and male/female threaded relief valves with high pressure air as well as with water.
The inspector reviewed the completed Unit 2 surveillance test procedure used to check leak tightness of RCS pressure isolation check valves.
The bases for acceptable leakage were also reviewed.
The test, entitled "Reactor Coolant System Pressure Isolation Valves Leak Rate Test," *"2-THP 4030 STP.226 Rev.
1 is used to demonstrate check valve closure for RHR and SI system check valves that perform an isolation function of protecting low pressure safety systems from full reactor coolant system. pressure.
Such valves are termed
"Event V" valves.
The leak checks were performed to satisfy both Technical Specifications and the Inservice Testing Program.
Such testing is required after each refueling outage prior to entry into MODE 3.
The inspector reviewed the completed test procedure and found it to be generally acceptable.
The current procedure was used, instrument calibration dates were within prescribed time limits, and all calculations were independently verified.
The inspector noted that three allowable leakage rates in the procedure were 10, 5, and 1 gpm; each were unique to specific valves.
Four "Event V" valves had allowed leakage rates of
gpm as specified in the Technical Specifications.
Of the remaining 18 valves, those tested alone were allowed
gpm leakage rate while those tested in pairs were allowed
gpm leakage rate.
Because
gpm could theoretically flow through 1 check valve, and this appeared to conflict with the allowable 5 gpm leakage for similar valves tested alone, the inspector questioned the acceptability of 10 gpm allowable leakage rate.
At the end of the inspection period, the licensee was unable to provide the basis for the
gpm leakage rate.
This is considered an Open Item pending the licensee's production of bases for these values.
(Open Item 50-316/90022-02)
One open item, and no violations, deviations, or unresolved were identified.
6.
Fire Protection 71707 64704 Fire protection program activities, including fire prevention and o~her activities associated with maintaining capability for early detection and suppression of postulated fires, were examined.
Plant cleanliness, with a focus on control of combustibles and on maintaining continuous ready access to fire fighting equipment and materials, was included in the items evaluated.
The licensee determined on September 21, 1990, that a postulated fire, as described in 10 CFR 50, Appendix R,
can disable heating, ventilation, and air conditioning (HVAC) systems for both control rooms.
Because the residual heat removal (RHR) flow indications are located only in the control room and the system is needed to place the Units in COLD SHUTDOWN, the licensee determined that control room evacuation caused by loss of HVAC systems from an Appendix R fire will affect the ability of Units to reach COLD SHUTDOWN two to three hours after the fire.
The licensee discovered this scenario while responding to questions raised by the NRC-sponsored Appendix R team inspection during the week of September 10, 1990.
This postulated fire does not affect the Units'bility to reach HOT SHUTDOWN.
The licensee has taken compensatory measures such as stationing fire watches, in the affected fire zones, and providing temporary ventilation equipment for the control room in an event of a fire.
Additionally, the licensee is considering design solutions and modifying their Appendix R procedure to allow the operators the ability to provide emergency alternate power sources to the control room ventilation fans.
Regional fire protection specialists are following this issue.
No violations, deviations, unresolved or open items were identified.
7.
Emer enc Pre aredness 82201 82203 The Unit 2 "CD" Emergency Diesel Generator was declared OPERABLE on August 30, 1990, which ended the Unusual Event condition caused by the planned evolution of both Unit 2 diesel generators being declared
inoperable on July 29, 1990, (Ref.
NRC Inspection Report 50-315/90021(DRP);
50-316/90021(DRP),
Paragraph 9. a).
Fuel was unloaded from the reactor during the entire time of the Unusual Event.
The licensee notified NRC prior to entering the unusual event condition.
No violations, deviations, unresolved or open items were identified.
Safet Assessment/
ualit Verification 37701 38702 40704 92720 The effectiveness of management controls, verification and oversight activities, in the conduct of jobs observed during, this inspection, was evaluated.
The inspector frequently attended management and supervisory meetings involving plant status and plans and focusing on proper co-ordination among departments.
The results of licensee auditing and corrective action programs were routinely monitored by attendance at Problem Assessment Group (PAG)
meetings and by review of Condition Reports, Problem Reports, Radiological Deficiency Reports',
and security incident reports.
As applicable, corrective action program documents were forwarded to NRC Region III technical specialists for information and possible followup evaluation.
No violations, deviations, unresolved or, open items were identified.
NRC Com liance Bulletins Notices and Generic Letters 92703 The inspector reviewed the NRC communications listed below and verified that: the licensee has received'the correspondence; the correspondence was reviewed by appropriate management representatives; a written response was submitted if required; and, plant-specific actions were taken as described in the licensee's response.
On September 7,
1990, the licensee was informed by the NRC Region III office that Whiting Corporation had submitted a
10CFR50 Part 21 Report regarding certain connection points on the containment polar cranes they manufactured which could be subject to overstress conditions.
The polar cranes had to be de'rated.
The 250 ton main and 35 ton auxiliary hoists were derated to 55 and 8 tons, respectively.
The problem was discovered when a Whiting engineer was doing calculation checks to see whether a similar crane belonging to another company could be upgraded to increased.capacity.
The Whiting corporation provided the licensee with the engineering design fixes which were reviewed and approved by corporate engineering in Columbus.
The files entailed adding four "stiffeners" at the stressed connections and replacement of a total of 32 connection bolts with bolts manufactured from a higher strength steel.
A complete visual inspection of the crane was also performed.
The work on the Unit 2 polar crane was completed on September 10, 1990, when the crane was returned to its original rating.
The Unit 1 crane underwent similar repairs which were completed on October 12, 1990.
No violations, deviations, unresolved or open items were identified.
10.
Re ion III Re uests 92705 On September 24, 1990, the licensee commenced preparation for establishing half-loop conditions on Unit 2 in order to repair reactor coolant system pressure isolation check valves which were found to be leaking during a
surveillance test.
The inspectors performed the items identified in the checklist for mid-loop/reduced inventory enclosed in the August 21, 1990, Region-III memo in order to ensure that procedures for mid-loop operation were written and addressed the appropriate concerns identified in, GL 88-17.
lhe inspectot s found that the licensee'
procedure,
"Criteria for Operating At a Reduced Reactor Coolant System Inventory," PMI-4070 established equipment and administrative controls which were necessary to operate the reactor coolant system in a reduced inventory condition.
The procedure required:
Two incore thermocouples to measure core exit temperatures and recorders in the control room to monitor the temperatures on a
continuous basis.
Two continuous RCS level indications were provided in the control room whenever the RCS level was below the top of the hot leg.
Availability of two additional RCS inventory replenishment paths in the event the RHR system was lost.
Availability of a diesel generator in the event normal power is lost.
Containment closure capability.
Establishing a hot leg vent path utilizing either the pressurizer manway or a primary side steam generator manway 'for all outages of sufficient duration.
Deferment of all evolutions affecting RHR, the RCS, or subsystems that interface with the RCS which could result in inadvertently draining the RCS to a time when the core is off loaded or the RCS has been refilled above the REDUCED INVENTORY level.
The inspectors found no discrepancies with the licensee's procedure used to prepare for mid-loop activities, Additionally, the inspectors found
'hat the repairs made to the check valves were successful (see maintenance section).
It was noted that the licensee normally off loads the fuel from the core prior to reducing RCS inventory to the mid-loop condition.
No violations, deviations, unresolved or open items were identified.
11.
~0ee Items Open Items are matters which have been discussed with the licensee, which will be reviewed further by 'the inspector, and which involve some action on the part of the NRC or licensee or both.
An Open Item disclosed during the inspection is discussed in Paragraph 5.f.
12.
Kana ement Interview 30703 The inspectors met with licensee representatives (denoted in Paragraph 1)
on October 12, 1990 to discuss the scope and findings of the inspection.
In addition, the inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents/processes as proprietary.
OGt C~ 8'0 l1r. Peter Kosick 5 Rochau 818 Ship Street P.O.
Box 25 St. Joseph, HI 49085
Dear I1r. Kosick,
As we indicated in our letter to you dated August 25, 1990, a copy of the results of the HRC's review of the July 13, 1990, electrocution event at the D. C.
Cook plant viould be provided when the investigation was completed.
The attached inspection report contains the final results of our investigation into this event.
j U
Although no specific root cause for the event was identified by the utility or by our investigation, several program weaknesses regarding lack of clear guidance and def'inition of responsibilities for preparing and reviewing clearance permit requests and job orders were identif'ied.
The cover letter to our report requests the utility to outline the corrective actions taken in response to these weaknesses.
Should you have any questions regarding the content of the report or our review, please contact Hr.
Edward G.
Greenman of my staff at 708/790-5518.
S incerely,
Attachment:
Inspection Report Hos. 50-315/90-21; 50-316/90-21 A. Bert Davis Regional Administrator
REGION III==
799 ROOSEVELT ROAO GLEN FLLYN, ILLINOIS 60137 O/ I 0 5 H93 V
Hr. Peter Kosick 8 Rochau 818 Ship Street P.O.
Box 25 St. Joseph; t11 49085
Dear 11r. Kosick,
As we indicated in our letter to you dated August 25, 1990, a copy of the results of the NRC's review of the July 13, 1990, electrocution event at
~ the D.
C.
Cook plant would be provided wheI> the investigation was completed.
The attached inspection report contains tne final results of
, our investigation into this event.
Altho'ugh no specific root cause for the event was identified by the utility or by our investigation, several program weaknesses regarding lack of clear guidance and definition of responsibilities for preparing and reviewing clearance permit requests and job orders were. identified.
The cover letter to our report requests the utility to outline the cor rective actions taken in response to these weaknesses.
Should you have any questions regarding the content of the report or our review, please contact Hr. Edward G.
Greenman of my staff at 708/790-5518.
S incere ly,
Attachment:
Inspection Report Nos. 50-315/90-21; 50-316/90-21 Regional Administrator
REGION III==
799 ROOSEVELT ROAD GLEN ELLYN, ILLINOIS 60137 Og P3 1990 Docket No. 50-315 Docket No. 50-316 Indiana Michigan Power Company ATTN:
Hr. Hilton P. Alexich Yice President Nuclear Operations Division 1 Riverside Plaza Columbus, OH 43216 Gentlemen:
This refers to the routine s'afety inspection conducted by J.
A. Isom, B. L. Jorgensen, D.
G. Passehl and R. L. Bywater of this office on July 18 through August 28, 1990, of activities at the Donald C.
Cook Nuclear Plant, Units 1 and 2, authorized by NRC Operating Licenses No.
DPR-58 and DPR-74 and to the discussion of our findings with A. A. Blind, and others of your staff at the conclusion of the inspection.
The enclosed copy of our inspection report identifies areas examined during the'nspection.
Within these areas, the inspection consisted of a selective examination of procedures and representative records, observations, and interviews with personnel.
No violations of NRC requirements were identified during the course of the inspection.
lieaknesses in your program were identified, however, by the portion of this inspection conducted by the NRC's Human Factors Assessment Branch on July,26 and 27, 1990, regarding the July 13, 1990, electrocution event which merit your consideration.
The weaknesses. pertained to lack of clear guidance and definition of responsibilities for preparing and reviewing clearance permit requests and job orders.
Based on the above, you should review the event to determine any need for additional controls (validations, sign-off, walkdowns, and verifications) to the clearance request and work review process.
This review should consider the need to incorporate drawings to accurately identify the location of plant equipment and the need for a plant standard regarding signs communicating personnel hazards throughout the plant.
After completing your review, please submit the results to the NRC Region III office.
In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter, and the enclosed inspection report will be placed in the'RC Public Document Room.
-7
Indiana Hichigan Power Company I
We will gladly. discuss any questions you have concerning this inspection.
S incere ly,
Enclosure:
Inspection Reports No. 50-315/90021(DRP);
Ho. 50-316/90021(DRP
)
REGION II I
'eports No. 50-315/90021(DRP);
50-316/90021(DRP)
Docket Nos. 50-315; 50-316 Licenses No. DPR-58; DPR-74 Licensee:
American Electric Power Service Corporation Indiana Michigan'ower Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Inspection Conducted:
July
Inspectors:
J.
A. Isom BE L. Jorgensen D.
G. Passehl Site, Bridgman, Michigan through August 28, 1990 Approved By:
B. L. Burgess, Projects Section ref 2A
~lns ection Summary 28 ~nI
.
/>>
n R~I~H
<<
<<'"P'7:
act>ons on previously identified items; plant operations including the electrocution event; radiological controls; maintenance; surveillance; fire protection and cleanliness; engineering and technical support; emergency preparedness; security; outages; safety assessment quality verification; reportable events; Bulletins, 'Notices and Generic Letters; Allegations; and, NRC Region III requests.
No Safety Issues Management System (SIMS) items were closed.
Results:
Of the 12 areas inspected, no violations or deviations were
~enti7ied in any areas.
Weaknesses were identified in your program regarding training of contractors and placarding of electrical cabinets.
Additionally, there were a number of Appendix R issues identified by the licensee which affected both Units.
Some of these Appendix R issues required immediate short term corrective actions by the licensee in order to ensure compliance with Appendix R requirements.
Plant Operations:
On August 23, 1990 at approximately 8:45 Ptl, Unit 2 operators energized valves which provided the suction path from the refueling water. storage tank (RWST)
to the charging pumps, as a part of the restoration from a half-loop.
Because of the existing low level in the volume control tank, when these suction valves were opened, flow path from the RWST to the primary system through the,.
charging pump suction cross-tie to the residual heat removal system was established.
Additionally, because the charging pump discharge cross-connect valves between'he two units and the cross tie drain valve were open, a flow path from the RWST to the Unit I charging pump room was established.
About 40,000 gallons of water was lost out of the RWST with most of the water filling the RCS, RHR, and the lower reactor cavity (an area normally flooded during refueling operations).
Some water drained into the Auxiliary Building sump and the lower containment area.
Inspection of the charging pump room and the lower containment area by the residents found minor or no equipment damage.
I Followup.of the July 13, 1990, electrocution event by the Human Factors Assessment inspectors determined that the licensee did not fully consider the information provided by the industry (Wolf Creek and San Onofre)
and NRC Information Notice ( IN) 88-96) regarding information learned from similar previous events.
Secondly, though there were inconsistent views on where the current transformers were located, the drawings that would have shown the location of the current transformers were not. used.
Finally, the licensee should review the event to determine the need for additional controls (validations, sign-off, walkdowns, and verifications) to the clearance request and work review process.
This review should consider the need to incorporate drawings to place the location of plant equipment and the need for a plant standard regarding signs communicating personnel hazards throughout the plant.
l.
On July 29, 1990, based on three separate walkdowns performed in the auxiliary building, licensee determined that inadequate emergency lighting existed as required by Appendix R.
The walkdown conducted by the licensee identified 61 Appendix R components and routes as being inadequately lit.
Additional Appendix R lighting is expected to be installed by August 31, 1990 under a expedited plant modification.
During the interim period, licensee has ordered miner's hard hats with battery powered lamps.
2.
On August 2, 1990, licensee determined that a potential loss of auto-start features for either all four ESW or all four CCW pumps could be caused by an electrical short due to a fire which, could destroy the cables for the ESW and CCW low header pressure switches.
Because these instrument cables for all four ESW or CCW pumps were located within one fire zone, it would be potentially possible for a fire to affect the auto-start feature for either the CCW or ESW pumps.
Additionally, because of a design implementation error, this postulated fire-induced electrical fault could not be isolated from the auto-start portion of the circuit with an installed fuse.
When the fuse coordination problem was identified, the licensee corrected the problem by replacing the existing 10-amp with a 5-amp fuse for the pressure switch circuits.
The electrical circuits will be modified to provide a permanent correction.
3.
On August 2, 1990, licensee determined that exposed structural steel members of walls which were located within five lube oil storage rooms did not have fireproofing material.
This condition was determined to be outside the design basis of the plant and is not covered by operating or emergency procedures.
4."
On August 24, 1990 licensee discovered that a postulated fire in any one of three Unit 1 fire areas affecting the cable between panels LSI-6 and LSI-6X could have resulted in an inability to maintain power to the LSI panels from Unit 1 or to repower these panels from Unit 2.
This scenario would have resulted in the loss of all process instrumentation used in Appendix R safe shutdown scenarios.
Licensee initiated a temporary modification to install a 1.25 amp fuse between panels LSI-6 and LSI-6X.
DETAILS 1.
Persons Contacted a.
Ins ection - Jul 18 throu h Au ust
1990
- A.
- J
- L K.
- B
- J
- p T.
J.
- T
- L J.
H.
D.
Blind, Plant Manager Rutkowski, Assistant Plant Manager - Technical Support Gibson, Assistant Plant Manager - Projects
.
Baker, Assistant Plant Manager - Production Svensson, Executive Staff Assistant Sampson, Operations Superintendent Carteaux, Safety and Assessment Superintendent Bei lman, Maintenance Superintendent Droste, Technical Superintendent
- Engineering
.
Postlewait, Design Changes Superintendent Matthias, Administrative Superintendent Wojcik, Technical Superintendent
- Physical Sciences Horvath, guality Assurance Supervisor Loope, Radiation Protection Supervisor The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
- Denotes some of the personnel attending the Management Interview on August 31, 1990.
b.
Mana ement Meetin
- July 31 1990 Licensee Personnel M. Alexich, Vice President
- Nuclear (AEP)
A. Blind, Plant Manager J. Rutkowski, Assistant Plant Manager - Technical Support L. Gibson, Assistant Plant Manager - Projects B. Svensson, Executive Staff Assistant P. Ha'ngan, guality Assurance Engineer J.
Kingseed, Senior Engineer, Nuclear Safety and Licensing B. Hennen, System Engineering Supervisor B. Worm, Administrative Compliance Coordinator
'A number'of other licensee personnel were also involved in discussing selected topics.
NRC Personnel J. Zwolinski, Assistant Director, NRR Division of Reactor Projects III, IV, and V.
J.
Isom, Senior Resident Inspector D. Passehl, Resident Inspector
Mana ement Visit Au ust 28 1990 Licensee Personnel A. Blind, Plant Manager
. J. Rutkowski, Assistant Plant Manager - Technical Support B. Svensson, Executive Staff Assistant S.
Faalow, Assistant Section Manager, ISC Section C. Savitscus, Instrument and Controls Engineer T. Langlois, Senior Project Engineer NRC Personnel B. Clayton, Branch Chief, Reactor Projects Branch 2, R-III B; Burgess, Section Chief, Projects Section 2A, R-III J.
Isom, Senior Resident Inspector D. Passehl, Resident Inspector 2.
Actions on Previously Identified Items.(92701 92702)
a.
(Closed)
Unresolved Item (316/88023-01):
The hydrogen skimmer'test
'rocedure contained acceptance criteria for compartment flows which was less conservative than the FSAR limits.
Licensee performed new analysis to show that even with the's-found lower compartment flows, post-accident hydrogen concentration would be less than that required by Regulatory Guide 1.7.
Additionally, the FSAR (Section 14.3.6)
was revised to reflect the revised lower compartment flows requirements.
b.
(Closed)
Unresolved Item (315/88012-01; 316/88014-01):
On March 30, 1988, the licensee learned from Limitorque Corporation that a torque switch design in some safety related Model SMB-00 motor operators had not been tested to verify their qualification.
The licensee has since replaced all unqualified torque switches in the affected Limitorque operators.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Verification (71707 71710 42700)
Routine facility operating activities were observed as conducted in the plant and'from the main control rooms.
Plant startup, steady'ower operation, plant shutdown, and system(s)
lineup and operation were observed as applicable.
The performance of licensed Reactor Operators and Senior Reactor.
Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
- The Plant Manager, Assistant Plant Manager-Production, and the Operations Superintendent were well-informed on the overall status of the plant, made frequent
. visits to'he control rooms, and regularly toured the plant.
Evaluation, corrective action, and response to off-normal conditions or events, if any, were examined.
This included compliance with any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
a 0 Unit I operated continuously at 100-percent power during this inspection period with no significant operational problems.
At the beginning of the inspection period, Unit 2 was in MODE 5 for a refueling outage.
On July 18, 1990, Unit 2 was placed in HODE 6 and unloading of the reactor core began July 26, 1990.
At the end of the inspection period, Unit 2 remained in NODE 6 and core reload
, is expected to begin on August 31.
Licensee entered a planned Unusual Event as defined in the Cook Nuclear Plant Emergency Classification procedure PHP 2080 EPP.101,
"Emergency Condition Category",
ECC-10 which states
"Loss of all on-site AC power capability (both diesel generators for one Unit are unavailable or inoperable due to mechanical, electrical, or error effects)."
Both Unit 2 emergency diesel generators were made inoperable for outage related work.
b.
On August 23, 1990 at approximately 8:45 PN, unit 2 operators energized valves 2-IHO-910 and 2-IH0-9ll, which provided the suction path from the refueling water storage tank (RWST) to the charging pumps, as a part of the restoration from a half-loop.
The restoration included removal of approximately 400 tags and restoration of numerous valves and breakers.
Because of the existing low level in the volume control tank, when valves 2-IHO-910 and 2-IHO-911 were opened, flow path from the RWST to the primary system through the charging pump suction cross-tie to the residual heat removal system was established.
Additionally, because charging pump discharge cross-connect valves between the two units were open and because the cross tie drain valve (I-CS-548)
was open, flow path from the RWST to the Unit I charging pump room was established.
This event lasted approximately one hour and about 40,000 gallons of water was lost out of the RWST.
Most of the water filled the RCS, RHR, and the lower reactor cavity (an area normally flooded during refueling operations).
Some water drained into the Auxiliary Building sump and the lower containment area.
The problem was discovered during a tour of the Unit I auxiliary building by the auxiliary equipment operator who noticed that the leak containment device for I-CS-548 was over-flowing.
The resident inspector made a tour of the Unit 1 charging pump room and areas of containment to determine the extent of damage to equipment and found through direct observations and interviews with plant individuals involved in the cleanup effort, that little or no equipment damage occurred.
~
I
At the end of the inspection period, licensee was still conducting their investigation into the August 23 event.
c.
Inspectors'imited walkdown of the Unit 1 safety injection (SI)
system found that valves were properly identified and none were mispositioned.
Inspectors used a valve lineup list from Procedure 1-OHP 4021.008.002,
"Placing Emergency Core Cooling System in Standby Readiness."
Approximately 100 components were checked to verify their proper identification and position.
Although there were no.major problems identified during the walkdown, inspectors did identify the following drawing discrepancies, and some material conditions which were identified to the licensee for corrective action:
(1)
Valve 1-SI-146N and valve 1-SI-146S, discharge drain valves for the North and South SI pumps, respectively, are listed on the valve lineup sheet but are not indicated on drawing No.
OP-1-5142-12.
(2)
Valve 1-SI-147N and valve 1-SI-147S, suction drain valves for the North and South SI pumps, respectively, are listed on the valve lineup sheet but are not indicated on drawing No; OP-1-5-5142-12.
(3)
Valve 1-SI-109N and valve 1-SI-109S, discharge valves for the North and South SI pumps, respectively, have pressure test gauges where the valve lineup sheet and drawings No.
OP-1-5142-12 indicates the valves are capped.
(4)
Dim lighting conditions in the South SI pump room required that flashlights be used during the inspection.
(5)
The junction box cover for the North SI pump inboard and outboard seal housing high temperature alarms ( ITA-251 and ITA-252) was loose.
Although the thermal sensors are non-safety related, procured commercial grade and the fai lure of the alarm to annunciate in the control room would not affect pump operability, the loose junction box cover was identified to the licensee because the alarms provide control room indication of possible low component cooling water (CCM) flow to the seals.
d.
Inspectors'ours in the auxiliary building to determine the adequacy of housekeeping, contamination control, and control. and coordination of activities found that, in general, conditions were acceptable considering Unit 2 was in an outage.
However, inspectors noted the following which were relayed to cognizant licensee personnel for appropriate action:
(i)
the work area atop the ice. machine was messy with hoses, drop cords and tools, and no work was ongoing;
a radiation control boundary rope for a temporary work area between the Unit 2 CCW heat exchangers was found lying on the floor; and, (iii)
'
tag for Job Order (JO)
B018816 was found on the floor behind a breaker panel on the 633-foot level, far from the component (2-HY-CIR-3) originally tagged on June ll, 1990.
Additionally, during the weekly tour with the Assistant Plant Manager
'APH)
to the Unit 2 4KV room and various areas of the auxiliary building, inspectors noted that the entrance to the auxiliary building from the turbine building needed some cleanup.
On July 13, 1990 a contractor electrician contacted an energized 4KV electrical feed cable in breaker cubicle T21C1.
The flash which resulted from the contact resulted in one fatality and seriously injured three personnel.
The licensee formed an accident investigation team which visited the accident scene, reviewed documentation associated with the work activity, and intervie'wed numerous licensee personnel to determine the cause of the accident and what actions, if any, were necessary at the site to prevent a similar occurrence.
Because the accident team was not able to interview the three survivors of the accident, the licensee has not yet closed the investigation.
The licensee's accident investigation team was not able to positively determine why the deceased contract electrician approached close enough to the energized conductors to initiate a fault; The licensee team determined that although none of the individuals involved in the accident knew the exact physical location of the current transformers, they had received training on plant safety policy which stressed that potentially energized equipment should be considered energized until positively proven de-energized.
Training on this electrical safety policy was performed during the Nuclear General Employee Training provided before the granting of unescorted access to protected areas.
The licensee's preliminary assessment of the electrical ac'cident and determined that the licensee had several program processes in place that could have prevented the accident.
First, the licensee found that
. although the design change and job order packages associated with the accident did not contain information on the location of the current
'ransformers, there were drawings onsite which contained information on the general location of the transformers.
The knowledge of the location of the current transformers by the technicians might have prevented the opening of the rear door of cabinet T21C1, exposing the technicians to'he energized 4KV cable terminals.
Secondly, the licensee's clearance process,,if properly performed, could have prevented the accident. by ensuring that all power sources were secured to the 721C1 cabinet.
The licensee found that although the clearance was performed as requested by the ISC technician involved in the accident, the clearance request was deficient.
Finally, the licensee required that supervisors responsible for an activity ensure that an appropriate job briefing be conducted.
The inspectors were informed that the job briefing was conducted by the instrument maintenance supervisor who was responsible for the installation of the design change.
After review of work control and training processes
.that were used, the licensee concluded that there was nothing wrong with the processes nor any violations that significantly contributed to the event other than a
failure to check that the equipment was de-energized.
Additionally, the inspectors noted that immediately after the accident, a stop work order was issued until the cause of the accident could be determined and training on configuration of electrical cabinets similar to T21C1 was given to the maintenance department.
Also, the importance of electrical safety was reiterated by the plant manager to all personnel through a
~
mandatory lecture.
The Human Factors Assessment Branch/NRR investigation conducted on July 26 and 27, 1990, indicated that improvements could, be made to the licensee's clearance request process.
These improvements concerned (I) clearly defining who is responsible for assessing the adequacy of the clearance boundary, (2) training for workers emphasizing the need for face-to-face communications when establishing clearances to minimize misunderstandings among workers, and (3) definition of the scope and extent of the clearance boundaries.
The inspectors also observed that the licensee could make improvements to the work process in the following areas:
planning and executing work and providing location drawings to workers.
Root cause assessment by the Human Factors Assessment Branch/NRR inspectors-determined that the licensee did not fully consider the information provided by the NRC ( IN 88-96)
and industry regarding similar previous events (i.e., Wolf Creek and San Onofre).
Secondly, though there were inconsistent views on"where the current transformers were located, the drawings that would have shown the location of the current transformers were not used.
Finally, a review of the event to determine (I) the need for additional controls (validations, signoffs, walkdowns, and verifications)
to the clearance request and work review process; (2) the need to incorporate drawings to show the location of plant equipment; and (3) the need for a plant standard regarding signs communicating personnel hazards throughout the plant was considered warranted.
The licensee's review of these three items is an open issue.
No violations or deviations were identified.
The NRC staff's request for an additional review by the licensee, discussed above, is considered an
'Open Item" to be closed by the NRC resident inspector (315/90021-01; 3I6/90021-01).
Radio log i ca 1 Controls (71707)
During routine tours of radiologically controlled plant facilities or areas, the inspector observed occupational radiation safety practices by the radiation protection staff and other workers.
Routine tours of the auxiliary building and containment indicated that, in general, workers were adhering to personnel radiation practices to minimize contamination and dose received.
Inspectors did find that because the exit pathway from the lower containment area was confined,
potential for cross contamination existed between those workers coming out of containment.
Additionally, the congestion in this area was increased because this exit path was also used by the workers to enter the lower containment area.
No violations, deviations, unresolved or open items were identified.
5.
Maintenance (62703 42700)
Maintenance activities in the plant, were routinely inspected, including both corrective maintenance (repairs)
and preventive maintenance.
Mechanical, electrical, and instrument and control group maintenance activities were included as available.
The focus of the inspection was to assure the maintenance activities reviewed were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specifications.
The following items were considered during this review: the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The following activities were inspected a.
Job Order JO B003754:
"Remove all intercell connectors on 2CD Battery.
Clean connectors and terminal posts.
Coat with NO-Ox-ID grease and reinstall."
Although there was no procedure used for the job, activities performed appeared to the inspector to be within the skill of the craft.
Additionally, the job order contained specific job.
attributes such as required torque values for the intercell connectors and the requirement to verify the presence of NO-OX-ID grease on the terminal posts.
Inspector did note that the handle of the torque wrench was not insulated to prevent accidental arcing.
The licensee responded that they would prepare a "guideline" which would address this concern.
b.
- 12 MHP 5021.082.017 Rev. 6:
"Preventive Maintenance of Installed, Motor and Valve Control Centers, and Overcurrent Testing of Molded Case Circuit Breakers."
Overcurrent testing of various breaker s in 600 Volt Motor Control Center EZC-A, located in the Unit 2 4KV switchgear room was observed.
The in-progress work was checked for proper documentation and that the procedure was being followed.'o problems were noted.
C.
- 12MHP4030.STP.046 Rev. 2:
"Emergency Diesel Generator System
Month Inspection" Inspector observed corrective maintenance performed on leaking Unit 2 CD diesel generator lube oil strainers and found no discrepancies.
Licensee was in the process of filling the lube oil system for the 18 month inspection of the diesel generator when they discovered that the lube oil strainers leaked excessively at the lube oil strainer top cover area.
The leak was
believed to be caused by a bad 0-ring and the 0-ring was replaced.
Although the craft did not have a detailed procedure to replace the O-ring, it appeared that the nature of the work was within the skill of the craft and the craft displayed good maintenance practices.
No violations, deviations, unresolved or open items were identified.'.
Surveillance (617~26
'42700)
The inspector reviewed Technical Specifications required surveillance testing as'described below and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were properly accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that deficiencies identified during the testing were properly reviewed 'and resolved by appropriate management personnel.
The following activities were inspected:
a.
- 12 THP 6030 IMP.014, "Protective Relay Calibration" for Unit 2 4KY breaker protective relays.
b.
- 12 HMP 4030 STP.047,
"18-month Surveillance Test Procedure for AB, CD, and N-Train Batteries and Chargers Using BCT-1000 Computerized Test System."
This test was observed on the Unit 2 CD battery; it utilized a load profile developed by the licensee's corporate office in about 1984-85 as an 8-hour drawdown to simulate post.-accident conditions.
This profile was augmented by the test engineer onsite, to both increase current draw and prolong it, through the test.
c.
- 12 OHP 4030 STP.046,
"New and Spent Fuel Hoist Height Interlock Operability Verification."
This test was being performed for the first time by the plant Operations Department (this was previously a Maintenance Department test) in company with the fuel handling contractor, Master-Lee.
d.
- 12 OHP 4030 STP.249,
"Containment Divider Barrier Seal Inspection."
The licensee was performing a Technical Specification required surveillance of the Unit 2 Divider Barrier Seal when it was determined the seal did not meet acceptance criteria.
The seal was declared INOPERABLE on August 1, 1990.
It was subsequently determined that all the seal material (Uniroyal 3807)
needed to be replaced due to cracks found under a backing plate that cannot be detected by visual inspection of the installed material.
- The replacement seal (Uniroyal 41300)
has superior properties (such as tensile strength, elongation, aging)
and is expected to be installed prior to startup of the unit.
P
Concerns about the integrity of the Unit 1 seal (Unit 1 is presently at power) were raised and addressed.
The licensee currently is, preparing a Justification for Continued Operation so the unit could continue operation for the remainder of the current cycle, scheduled to end mid-October, 1990; At that time, replacement of the 3807 material in Unit 1 will be performed.
e.
- 1 IHP 4030 STP.003,
"Reactor Coolant Flow Protection Set III Surveillance Test (Honthly)."
This test described the procedure used by the ISC technicians to determine the operability of the reactor coolant system flow protection set III by verifying the proper.flow bistable tr ip values.
Additionally, loop low flow indications in the control room was verified.
Inspector observed the IEC technician perform the surveillance and
. reviewed the procedure and noted no discrepancies.
The inspector found that the surveillance proc'edure was generally well written, all voltages were within the required tolerances, and all indications in the control room functioned as required.
Additionally, the ISC technician displayed good working knowledge of the procedure and the anticipated system indications as a result of initiating various signals throughout the test.
Ho violations, deviations, unresolved or open'items were identified.
7.
Fire Protection (7170~7 64704)
Fire protection program activities, including fire prevention and other activities associated with maintaining capability for early detection and suppression of postulated fires, were examined.
Plant cleanliness, with a focus on control of combustibles and on maintaining continuous ready access to fire fighting equipment and materials, was included in the items evaluated.
E Licensee identified the following Appendix R issues during this inspection period:
On July 29, 1990 the licensee determined reportable to NRC a situation where potentially inadequate lighting existed in areas of the auxiliary building requir ed for emergency remote shutdown of the reactor per 10CFR50 Appendix R.
The lighting conditions were evaluated during three separate walkdowns of the auxiliary building starting on April 19, 1990 and ending on July 17, 1990.
The licensee believed the safe shutdown could have been performed since operators normally carry flashlights while executing their regular plant duties.
Short term corrective actions were addressed with procurement of hardhats with lights mounted to the front and powered by battery packs attached at the waist.
Long term
corrective actions scheduled to be complete on August 31, 1990 included upgrading the system with more lighting focused at the proper locations.
b.
C.
d.
On August 2, 1990 a concern that cable routing for component cooling water (CCW) and emergency service water (ESW)
pump control circuitry did not meet 10CFR50 Appendix R requirements was reported to NRC.
Specifically, the cabli'ng for the ESW and'CW low header pressure switches were located in the same fire area and did not meet Appendix R separation criteria.
Because of a fuse coordination problem between the automatic start switch and the rest of the circuitry, it was possible for a short circuit in the pressure switch wiring to disable the CCW and ESW pumps auto-start capability.
The problem was corrected when it was identified by replacing fuses in the pressure switch circuitry.
On August 24, 1990'icensee discovered during a review of a licensee problem report that because of cable routing for a cable associated with the Unit 1 shutdown indication (LSI) panels, a postulated fire
'n any one of three Unit 1 fire areas (Fire Zones 41, 55 or 56)
could have resulted in an inability to maintain power to the LSI panels from Unit 1 or to repower the panels from Unit 2.
This scenario would have resulted in the process monitoring instrumentation used in the Appendix R safe shutdown scenarios to become unavailable.
The cable is 1-2968G, which connects LSI panel 6 to panel 6X.
The routing for the cable 1-29685G includes Fire Zones 41, 55, and 56.
A postulated fire in any of these zones could create a
fault on cable 1-29685G and has also been found to fail the ELSC bus on Unit 1.
Since the cable is not fused at the present time, a switchover to the Unit 2 ELSC bus for LSI panel 6 would place the fault on the Unit 2 bus and result in failure of that bus.
Unless the leads to the shorted cable at LSI panel 6 were lifted, the result would be total loss of power to all of the Unit 1 LSI panels.
Additionally, credit for control room process monitoring instrumentation cannot be taken for this situation because instrumentation is powered by the CRIDS which are also postulated to fail in the event of a fire in the affected areas.
Licensee initiated a temporary modification to install a 1.25 amp fuse between panels LSI-6 and LSI-6X.
t Additionally, licensee determined on August 2, 1990, that as a
result of surveillance inspection and field walkdown performed of existing fireproofing on June 15, 1990, that fireproofing material was not installed on exposed structural steel members of walls in the following lube oil rooms:
Unit 1 - Turbine lube oil room Unit 1 - Turbine oil tank room Unit 2 - Turbine lube oil room Unit 2 - Turbine oil tank room Unit 2 - fhisc. oil storage room
The fire detection system(s)
are wired into the control room alarm system which should alert and cause the dispatch of the fire brigade.
In addition, the suppression system(s)
are detector actuated C02 dispensing type and are present in all the subject rooms.
The issues discussed in this section will be reviewed during an Appendix R
inspection scheduled for September 10 through 14, 1990.
8.
Ep ~d
~hi 1S The inspector monitored engineering and technical support activities at the site and, on occasion, as provided to the site from the corporate office.
The purpose of this monitoring was to assess the adequacy of these functions in contributing properly to other functions such as operations, maintenance, testing, training, fire protection and configuration management.
a
~,
On July 26, 1990, the resident inspector office was informed by site management of a potential weld deviation existing for certain model Centrifugal Charging and Safety Injection Pumps manufactured by Dresser Pump Division (previously, Pacific Pump Division).
The information was transmitted to the licensee in a July 2, 1990 Westinghouse letter which stated a concern that welds associated with the inboard locating lugs and outboard centering fins may not meet the manufacturer's minimum acceptance criteria.
D. C.
Cook was not listed as having the Safety Injection Pumps in question.
They were, however, referenced as having been supplied the Charging Pumps.
The letter recommended, and the licensee performed, inspection of the welds to ensure adequate deposit of weld material.
The inspection identified weld deposit ranging from about 14-percent to 60-percent of that necessary under the generic loading assumptions provided by Westinghouse.
The licensee pursued plant specific loading assumptions along with possible weld enhancements and began the process for an NRC Waiver of Compliance request.
A few days later, the results of the plant specific analysis done by Dresser and the licensee's corporate office found that minimum weld requirements based on service nozzle loading and seismic forces (supported by values contained in the Final Safety Analysis Report)
were met with the as-found condition.
The "worst" Charging Pump met the minimum weld area by about 17-percent.
The licensee is deciding whether to pursue plans for laying additional weld material during the next set of refueling outages, a possible design fix which would eliminate the need for the welds completely, or leaving the welds "as is" based on engineering review.
b.
On July 23, 1990, the resident inspector office was informed that eddy current testing of the Unit 2 incore flux monitoring, thimble tubes showed the tubes to be substantially degraded.
Of the
total tubes:
II
-15 had indications of approximately 40-percent through-wall degradation-1 had indication of approximately 50-percent through-wall degradation-6 had indications of approximately 60-percent through-wall degradation-2 had indications of approximately 90-percent through-wall degradation-1 had indication of 100-percent through-wall degradation (was leaking)
All of these thimble tubes were previously replaced during the last refueling outage in 1988.
A few weeks prior to the outage, a tube which had 100-percent through-wall was isolated after-it was identified as leaking (Ref.
NRC Inspection Report 50-315/90013(DRP);
50-316/90013(DRP),
Paragraph 2.b).
, The thimble tubes, manufactured by Westinghouse, were installed at other U.S. utiliti'es where this degree of wall loss has not been experienced.
In an attempt to identify the cause of the aggressive wall loss, Westinghouse and the licensee reviewed plant operating conditions during previous fuel cycles as well as fuel assembly geometry.
A concern was expressed with Unit 1 thimble tubes as they are also of the same material and dimensions as the Unit 2 tubes; however, no problem has yet been identified at Unit 2.
The licensee has replaced all 10 tubes which were determined to have greater than 50-percent through-wall reduction.
The investigation to determine the root cause of the thimble tube thinning was still in-progress as this inspection period came to a close.
No violations, deviations, unresolved or open items were identified.
9.
Eme~r ency Preparedness (82201~ 82203)
On July 29, 1990, the licensee carried forth a planned evolution regarding a dual emergency diesel generator outage which placed the unit in an Emergency Plan "Unusual Event" condition.
Unit 2 Train A Diesel Generator was made inoperable to allow work on its 4160 Volt Emergency Bus (Paragraph 3.a.)
and Train B Diesel Generator was removed from service, as planned, and declared INOPERABLE to perform Technical Specification required inspections.
The unit remained in an Unusual Event condition at the close of the inspection period.
Train A diesel generator is expected to be declared operable around August 31, 1990'.
No violations, deviations, unresolved or open items were identified.
10.
Security (71707)
Routine facility security measures, including control of access for vehicles, packages and personnel, were observed.
Performance of dedicated physical security equipment was verified during inspections in
various plant areas.
The activities of the professional security force in maintaining facility security protection were occasionally examined or reviewed, and interviews were occasionally conducted with security force members.
On August 3, 1990, and again on August 18, 1990, the licensee reported to HRC that a contractor supervisor tested positive for alcohol.
The earlier event resulted from a random Fitness For Duty (FFD) test; the latter from an attempt to enter the protected area while under the influence.
In both cases, site access was suspended, among other things, in accordance with the licensee's FFD policy.
Ho violations, deviations, unresolved or open items were identified.
Outa es (37700 42700 60705 60710 61701 61715 86700)
In response to Generic Letter 88-17,
"Loss of Decay Heat Removal," the licensee committed to install two independent electronic monitoring systems which would monitor the reactor coolant system (RCS) level during reduced inventory operation.
The inspector observed installation and performed a walkdown of accessible portion of the system.
The RCS mid-loop system consists of two electrically independent level indication system and a sight glass.
One level indication system is a standard differential pressure transmitter type and a second indication
"
system is a capacitance probe type.
Additionally, there is a local sight glass with can be viewed with a video camera in the control room.
Both electrical level detectors also have remote indications in the control room.
The narrow range level detector (capacitance probe type) is 'connected to the number two hot leg piping and the loop's bypass temperature manifold.
This instrument readout is from just, below the half loop to the top of the hot leg.
The wide range level detector (differential pressure type) is connected to the the piping from the number four steam generator to the reactor coolant pump (intermediate leg) and to the vent piping from he pressurizer.
This instrument readout is from approximately reactor vessel flange level to the bottom of the hot leg.
No violations, deviations, unresolved or open items were identified.
Safety Assessment/Oualit Verification (35502 37701 38702 40704 92720)
Inspector performed Inspection Procedure 35502, "Evaluation of Licensee guality Assurance Program Implementation" and found that the licensee is generally showing improvements or has improved in 3 of the 7 SALP function areas since the SALP 7 cycle.
These three areas where improvements have been evident were plant operations, emergency preparedness, and security.
In the other 4 SALP functional areas, radiological controls, maintenance/surveillance, engineering/technical support and safety assessment/quality verification, it was difficult to determine whether improvements made by the licensee have contributed k
12.
13.
towards, major improvements in these areas.
Examination of the numerical ratings in the SALP categories for these 4 SALP functional areas appeared to indicate that there were no ndgative trends developing and that the licensee has maintained a steady performance in these areas.
The purpose of the inspection procedure was to evaluate the effectiveness
'f the licensee's implementation of its quality assurance program by reviewing inspection reports for the past 12 months, SALP reports for the past',years, outstanding Regional open item list, licensee corrective actions for NRC inspection findings, and LERs for the past 12 months.
The inspector, based on review of these documents, determined whether negative trends could be determined which could indicate problems with the licensee's gA program implementation.
No violations, deviations, unresolved or open items were identified.
Allegations (92705)
Allegation Follow-up (AMS No. RIII-90-A-0059)
Discussed below is an allegation received by the NRC Region III Office relating to surveillance tests at D. C. Cook, which was evaluated during this inspection.
The evaluation consisted of record and procedure review and interviews with licensee personnel.
~
Allegation:
A surveillance test on an Engineered Safety features Ventilation Unit (AES Fan)
was not redone during August 1982 to cover steps missed in part of the procedure.
Additionally, it was common practice for technicians not to obtain required signatures indicating control room notification until after the test was completed.
Discussion:
Surveillance test records for the AES fans associated with botR units were reviewed.
A historical record for surveillances performed since the early 1980's was retrieved, with review emphasized on several tests completed since 1985.
No significant problems were noted during the review, and no violation of Technical Specification surveillance requirements were noted.
Several procedures were sampled and individuals interviewed to see if control room notification requirements were being fulfilled. All documents reviewed showed control room concurrence, verbal or written (some procedures allow for verbal notification), prior to start of surveillance tests.
All individuals interviewed indicated understanding of the notification requirements; F~indin
The a11egation was not substantiated No violations, deviations, unresolved or open items were identified.
e~l (>>i a.
In response to a May 25, 1990 memorandum from the Director, Division of Reactor Projects, Region III, this inspection included an investigation into the licensee's methods for monitoring and controlling Zebra mussels.
On July 18, 1990, divers discovered two adult Zebra mussels in the screenhouse intake forebay.
Problem Report (PR) 90-0945 was generated to document the finding and provide a mechanism to track action on the discovery.
The licensee already had a program in place to monitor biological fouling as a result of commitments made in response to NRC Generic Letter 89-13 (Service Water System Problems Affecting Safety-Related Equipment).
This included collection/analysis of sediment and substrate samples as well as water samples.
A beach walk program was also instituted for Zebra mussel colonization.
b.
To aid in formulation of the plant's Zebra.mussel control strategy, meetings were held with three vendors which were familiar with Zebra mussel control on July 25, 1990.
The next day, an informational meeting with the Michigan Department of Natural Resources (MDNR),
among others, concluded with a presentation of the plant's suggested
, control strategy.
The MDNR indicated that the use of a molluscicide could be approved in a relatively short time frame, provided the product had been previously approved for use elsewhere in Michigan.
The plant requested, in a letter, use of such a product (Clam-Trol CT-1) along with an easing of chlorination limits.
The licensee's sampling and analysis program for Zebra mussels is contained in Procedure No.
THP 6020 ENV.101.
At this writing, the procedure is in draft form and out for comments.
No major changes are expected to be added.
Areas of the plant to be sampled at various locations include the Circulating Water, Service Water, and, Fire Protection Systems.
The results of the sampling and analysis program are expected to be included in the licensee's Annual Environmental Operating Report.
In response to a July 10, 1990 memorandum from the Director, Division of Reactor Projects, RIII'to Senior Resident Inspectors, several examples regarding Technical Specification Limiting Condition of Operation (LCO) Action Statement entries were'rovided to the Region III Technical Support staff.
The specific examples were restricted to those for which preventive maintenance was performed.
The examples included the affected equipment, the LCO entered, and the actual time,require'd to perform the maintenance.
No violations, deviations, unresolved or open items were identified.
I
. l~
~i(>> 02)
a.
On July 31, 1990, the licensee hosted an NRC management visit by Hr. John Zwolinski, Assistant Director, NRR Division of Reactor Projects III, IV, and V.
The purpose of the meeting was to discuss various licensee initiatives and to tour the plant.
4 t a
r,
Among the topics discussed were:
Unit Two outage status flodification in progress Design Change proce'ss f1aintenance program update Human Performance Enhancement System (HPES)
System Engineer concept and experience to date b.
On August 27, 1990, the licensee was visited by Messrs.
Brent Clayton, Chief, Reactor Projects Branch 2 and Bruce Burgess, Chief, Projects Section 2A.
The purpose of the visit was to review the licensee's installation of the half loop instrumentation, to tour Unit 2 containment, and various areas of the Auxiliary and Turbine buildings.
15.
management Interview (30703)
The,inspector met with the licensee representatives (denoted in Paragraph l.a)
on August 31, 1990, to discuss the scope and findings of the inspection as described in these details.
In addition, the inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such document/processes as proprietary.
'I