IR 05000315/1990027
| ML17328A944 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 02/13/1991 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A943 | List: |
| References | |
| 50-315-90-27, 50-316-90-27, NUDOCS 9102270096 | |
| Download: ML17328A944 (23) | |
Text
'
U. S; NUCLEAR REGULATORY COMMISSION REGION II I Report Nos. 50-315/027(DRP);
50-316/027(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
1 Inspection At:
Donald C.
Cook Site, Bridgman, MI Inspection Conducted:
December 21, 1990 through February 5, 1991 Inspectors:
J.
A. Isom E.
R. Schweibinz D. S. Butler R.
K. Ewing D.
G. Passehl Approved By:
B.
J r ensen, Chief Pr jec ection 2A Ins ection Summar
,
DA i >/Sl Ins ection on December
1990 throu h Februar
1991 (Re ort Nos.
-
2 Areas Ins ecte
Routine unannounce inspection by the resident inspectors o
- actions on previously identified items; plant operations; maintenance; surveillance; design changes and modifications; engineering and technical support; security; reportable events; and, allegations.
No Safety Issues Management System (SIMS) items were closed.
In addition, a routine periodic management meeting was held among licensee and NRC staffs on February 1, 1991, in the NRC Region III offices.
Results:
Of the 9 areas inspected, no violations or deviations were identified
>n any areas.
The inspection identified no notable strengths or weaknesses n any of the inspected areas.
No new open or unresolved items were identified.
910227009b 9102i 4 PDR AVOCA Q5000315
pro For most of the inspection period, Unit 1 was in a refueling outage, which began on October 19, 1990.
A11 major milestones were successfully achieved and no significant safety issues occurred as a result of activities associated with this outage.
Start up activities'enerally progressed as anticipated with system para llel occurring on January 26, 1990.
The unit was operating at 100-percent power at the close of the inspection period.
Unit 2 likewise experienced no.major operational problems and remained at essentially 100-percent power throughout the inspection period.
f~aintenance and Surveillance:
Review and inspection of the surveillance and maintenance activities during'his period indicated no significant strengths or weaknesses and surveillance and maintenance activities were performed satisfactorily.
E
DETAILS 1.
Persons Present at:
a e Mana ement Meetin (Februar
1991)
American Electric Power / Indiana Michi an Power D.
H. Williams,'Jr., Senior Executive Vice President (VP)
AEPSC H. P. Alexich, VP, Nuclear Operations, AEPSC E.
E. Fitzpatick, Executive Assistant, AEPSC A. A; Blind, Plant Manager L; S. Gibson, Assistant Plant Manager, Projects T. 0. Argenta, Assistant VP, Nuclear Engineering, AEPSC R.
F. Kroeger, Manager
'- Electrical Systems Division AEPSC S. J. Brener, lianager, iinciear Safety and Licensing IiiSSL), AEPSC J.
A. Kobyra, Group Manager, Nuclear Design, AEPSC N. Ruccia, Manager, Structural and Analytical Design, AEPSC B.
P.
Lauzau, Senior Engineer, NS8:L, AEPSC V. A. Lepore, Assistant VP -Design, AEPSC Nuclear Requlatory Commission (NRC):
NRC Re ion III and Headquarters:
b.
A.
B. Davis, Regional Administrator H. J. Hiller, Director, Division of Reactor Projects (DRP)
T. 0. Hartin, Director, Division of Reactor Safety L. B. Harsh, l'RR, Director, PD3-1 H.
B. Clayton, Chief, DRP Branch
B. L. Jorgensen, Chief, Projects Section 2A E.
R. Schweibinz, Senior Project Engineer J.
A. Isom, Senior Resident, D.
C.
Cook B.
E. Holian, NRR, Project Manager J.
A. Gavula, Reactor Inspector N.
C. Choules, Reactor Inspector R. L. Bywater, Reactor Engineer NRC Resident Exit (Februar
1991)
A.
- J
- L
- K
~B.
- J P.
T.
T.
L.
J.
H.
D.
A. Blind, Plant Manager R. Rutkowsl'i, Assistant Plant Manager - Technica'l Support S. Gibson, Assistant Plant Manager - Projects R. Baker, Assistant P'lant Manager - Production Svensson, Executive Staff Assistant R.
Sampson, Operations Superintendent F. Carteaux, Safety and Assessment Superintendent P. Beilman, Maintenance Superintendent B. Droste, Technical Superintendent-Engineering K, Postlewait, Design Changes Superintendent J. Matthias, Administrative Superintendent T. Ilojcik, Technical-Superintendent
- Physical Sciences L. Horvath, equality Assurance Supervisor C. 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 ttanagement Interview on February 7, 1991.
2.
Actions on Previously Identified Items (92701 92702)
a ~
NRC Region III Hanagemen't has reviewed the existing open items for the 0.
C.
Cook station and has determined that the following open items wi 11 be closed administratively based on their age and their relative safety significance as compared to other emerging priority issues:
Unit
Unit 2 315/79001-BB (Bu1 1 etin)
315/85006-GL (Generic Letter)
316/79001-BB (Bul 1etin)
316/85006-GL (Generic Letter)
316/85001-PP (Part 21)
The licensee is reminded that commitments directly relating to these open items are the responsibility of the licensee and should be met as committed.
NRC Region III wi 11 periodically review licensee's actions associated with the administratively closed open items on a sampling basis.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Yerification (71707 71710 42700)
Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant start-up, 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, arid the degree of professionalism of control room activities.
The Plant Hanager, Assistant Plant Manager-Production, and the Operations Superintendent were well-informed on the overall status of the p'lant, made frequent visits to the control rooms, and regularly toured the plant.
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..
a
~
Unit I began the inspection period working towards the end of the refueling outage that began on October 19, 1990.
All major milestones were successfully achieved and no significant safety issues occurred as a result of activities associated with this outage.
Start up activities generally progressed as anticipated with system parallel occurring on January 26, 1990.
The unit was operating at 100-percent power at the close of the inspection perio b.
Unit 2 likewise experienced no major operational problems and remained at essentially 100-percent power throughout the inspection period.
No violations; deviations, unresolved or open items were identified.
4.
t1aintenance (62703 42700)
t<aintenance activities in the plant were routinely inspected, including both corrective and preventive maintenance.
thechanical, 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 prio'r 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 B005238 was written to document replacement of the
,Hoodward governor on the Unit 2 Turbine Driven Auxiliary Feedwater Pump (TDAFP), which resulted from gross water in-leakage into the governor oil system after the governor oil cooler had failed.
Maintenance procedures and testing results associated with this job were reviewed because the TDAFP oversped during surveillance testing about one week after completion of this job.
The review included interviews with the newly-appointed system engineer and the technicians who performed the work.
The inspector also checked for incorporation of vendor recommendations into the associated maintenance procedures.
The reviews found the TDAFP governor change-out was completed satisfactorily within the time allowed by the Technical Specifications and that post-maintenance test results were acceptable.
Some concerns were identified related to vendor-recommended'aintenance practices and procedure quality, which were discussed with the appropriate Maintenance Department supervisors.
The governor change-out was performed in accordance with plant procedure
- 12 tIHP 5021.056.003,
"f1aintenance Repair Procedure for Auxiliary Feed Pump Turbine."
The procedure was generally clear ahd easy to follow but since it addressed the disassembly and repair of the entire turbine, it was quite lengthy and a great amount of the document had to be marked
"Not Applicable."
Only the smaller portion that was relative to the governor was completed.
The procedure section or, governor removal and installation coincided with the vendor manual with the exception of a vendor-recommended adjustment
The inspector was also informed that a
new procedure is being drafted to address maintenance on only the TDAFP governor, and would include the vendor recommendation regarding the adjustments to the compensating system.
The root cause(s)
of the TDAFP overspeed events could not be absolutely determined.
The surveillance activities relative to this event are discussed in paragraph 5.b of this report.
Job Order B53612,"Perform monthly preventive maintenance diesel."
The inspector reviewed a recent monthly routine maintenance activity on Unit 2 CD Emergency Diesel Genera procedure used, VHI-5030 (Preventive maintenance and Envf n
CD preventive or.
The onmental heckin qualifications - Task 10), detailed the requirements for c g
each fuel pump and associated linkage for damaged or bound parts.
The maintenance technicians who performed the task were knowledgeable about the equipment and its operation.
The procedure was clear, data was properly 'documented, and no unacceptable conditions were noted.
The inspector reviewed the licensee's program and implementation of protective measures for extreme cold weather.
The program is outlined in procedure tlHI-5030, Preventive Maintenance and Environmental qualifications - Task 30, and consists of required actions to assure that safety-related process, instrument, and sampling lines do not freeze during extremely cold weather.
Job Orders A28524 and A28525 were written to document program implementation for mechanical and electrical tasks, respectively.
The review found that the licensee has adequate mechanisms in place to prevent susceptible systems from freezing using heat tracing, space heaters, and insulation.
The inspector verified the licensee inspected those systems and ensured that the various heat tracing and space heaters were energized.
Additiona'lly, building penetrations to the outside environment were covered as required per the licensee's procedure.
t<o,,unsatisfactory conditions were noted during the inspector's review.
to the compensating system.
The vendor recommended this adjustment on newly installed governors to remove trapped air from the governor
, hydraulic circuits and ensure TDAFP operating stability. The inspector questioned whether the apparent lack of adjustment may have contributed to the TDAFP overspeed, and was informed by the maintenance technician who worked the job that the adjustment had been made using the vendor manual as a guide.
This action was not" documented in the maintenance procedure, nor on the job-order, and appears contrary to the intent of plant procedure PHI-2290 ("Job Orders" ), which states at Step 4.4.6, that documentation of work done
"...must be complete-,
accurate, and of sufficient detail to provide a
clear explanation of exactly what work was performed."
This example of poor work documentation was discussed with licensee management.
The inspector was informed that the vendor recommendation was submitted fo'r incorporation into the above TDAFP repair procedur The inspector observed activities associated with corrective maintenance 'for removal of a damaged 4KV bus shutter.
While preventive maintenance was being performed on the Unit 2 West Essential Service Water (ESW)
pump, its 4KV breaker (T21A5) was racked out under Clearance Tag 2-1192.
Upon attempting to return the pump to service on January 14, 1991, the operator racking the breaker in noticed increased physical resistance and stopped.
The 4KV bus shutter had failed to completely retract and was slightly damaged during the racking-in process.
The licensee documented this situation on Problem Report 91-0096 and Condition Peport 1-01-91-0125.
They also entered a
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Limiting Condition for Operation (LCO) upon the identification that the breaker was inoperable.
The situation was further complicated by the fact that the associated 4KV bus also supplied power to the Pressurizer Heaters.
The inspector observed the decision process plant management went through to arrive at their final course of action.
Three options were identified, The first was to shut the plant down, deenergize the bus, and make the repair.
The second was to increase pressure in 'the primary system toward the upper end of the operating band, deenergize the bus, and make the repair and energize the bus before pressure dropped to the point that other problems would occur.
The third option was to make the repair with the bus remaining energized.
The licensee pursued all three options concurrently and ultimately decided on the third option once they convinced themselves that it could be done safely.
The situation inside the breaker cubicle was mocked up in the
'icersee's training faci lity and dry runs were conducted.
Indiana Hichigan Power Company high voltage experts were called in as consultants.
Prior to even considering this option, one of the electrical supervisors had volunteered to perform the task of removing the 4KV shutter.
The inspector observed the various options for removing the shutter and also the dry runs.
In the field, the inspector observed the use of proper safety equipment, the removal of the breaker from the 4KV cubicle, the condition of the shutter (slightly damaged and also
cocked at about a
10 degree angle from its normal position); the location of small shutter fragments, the placement of the insulating blankets in the cubicle, the shutter after it had been removed, the condition of the cubicle after the shutter and its fragments had been removed, the removal of the insulating blankets, and the reinstallation of the breaker.
A red warning sign was placed on the breaker cubicle.
The inspector further observed the lifting of the clearance, the racking in of the breaker, the star ting of the west ESW puinp, and its return to service.
Al'l activities were performed in a safe and professional manner.
One area for improvement was the visual inspection and air test of high voltage insulating gloves prior to each use and prior to placing them inside of the leather outer glove.
The inspector observed a few
-
cases where air testing of the insulating gloves was not done prior to each use.
Use of sleeves, safety glasses, faceshields, flashcoats, and overshoes was appropriate.
No violations, 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, and that test results conformed with Technical Specifications.
Additionally, the inspector verified that procedure requirements 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.
- 2 IHP 4030 STP. 107,
"Overtemperature and Overpower Protection Set IV Surveillance Test (tionthly)."
The test was performed to verify OPERABILiTY of reactor coolant loop 4 Delta T and Tavg reactor trip system instrumentation.
The test method involved use of simulated signals that correspond to reactor overpower and overtemperature conditions.
The bistables that sense those conditions are monitored to insure they actuate within a range of specified values (i.e. voltages).
No problems were noted with performance of this procedure.
The measuring and test equipment was checked and found to be within the calibration due dates.
The technicians performing the test exhibited good communications and the procedure was easy to follow and all measured voltages were within the specified ranges.
b.
- 2 OHP 4030 STP.017T,
"Turbine Driven Auxiliary Feedwater System Test."
The test was performed to demonstrate OPERABILITY, in accordance with the Technical Specifications, of the Unit 2 TDAFP, after its associated governor was replaced with an equivalent
'overnor from the Unit 1 TDAFP.
The test was reviewed because the inspector learned the TDAFP oversped twice, on successive runs, about a week after the governor replacement.
The inspector reviewed ihe test procedures and interviewed personnel involved with the tests.
The reviews found the licensee successfully repaired the problem with the governor and the TDAFP was made OPERABLE within the time constraints allowed by the Technical Specifications.
Although no major problems were noted, some areas of the test documentation were of poor quality and the inspector reviewed these areas with the Operations Department Superintendent.
The inspector's review of maintenance associated with the governor change-out (see paragraph 4.a.) is also discussed in this repor The problem with the governor, which functions to regulate the steam flow to the turbine to maintain constant pump speed under'arying load conditions, was noted by an Auxiliary Equipment Operator (AEO)
while making a routine plant tour.
The AEO found water in the TDAFW oil system which is a possible indication of governor oil cooler failure resulting in water in-leakage into the governor oil system.
A 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification ACTION STATEMENT was entered and Job Order B005238 was written to replace the governor (a spare governor was being rebuilt at the time).
After the governor change-out was completed, two OPERABILITY tests were performed.
The governor'failed to cycle correctly during the first test and the surveillance was aborted so maintenance technicians could vent and adjust the governor.
The second test was then run and the pump responded proper ly, met the procedure acceptan'ce criteria,.and was declared OPERABLE. within the required time-frame.
A concern with the test documentation was identified when the inspector noted that temporary test gauges used to verify cooling water flow through the turbine and governor oi 1 coolers were not installed as stated in the "Initial Conditions" section of the procedure.
The associated step in the procedure stated that use of the gauges were "not applicable" because the pump was being tested outside the normal surveillance interval and that, according to plant procedure PflI-4030 (Technical Specification Review'and Surveillance)
some portions of surveillance test procedures "...
may be marked not applicable for retesting of certain components."
The pump, nevertheless, met the post-maintenance testing requirements
.
as stated in the "Technical Specificati'on and Testing" form, which was part of the governor change-out job package.
The following week the pump was again tested to satisfy an increased frequency test request by Operations Department.
This increased test frequency was partly due to the governor problem but also because of implementation of the reliability-centered maintenance program.
Although the TDAFP eventually ran successfully and met the acceptance criteria listed in the test procedure, it oversped on two successive attempts.
It ran succe'ssfully, on the third try, after the governor was vented and re-adjusted.
Operators involved with the test were interviewed and the completed procedure was reviewed.
The inspector identified no major concerns although the inspector did note that data for two surveillance tests were included on one surveillance test procedure.
The procedure listed data for one of the overspeed events (the second overspeed attempt was not documented as it was considered
"troubleshooting" ), and also data for the successful OPERABILITY run.
This practice was questioned since in parts of the procedure it was difficult to ascertain which set of data were applicable for the tests performed at different periods.
The licensee was asked how aborted survei llances in general are handled and it was noted that no procedure or instruction currently
addressed the subject.
Operations Department stated the practice would be evaluated, and they would inform the inspector of the results.
c.
I OHP 4030.001.002,
"Containment Inspection Tours."
The inspector accompanied licensee personnel on the final pre-startup Unit I containment inspection and found no significant discrepancies.
A small amount'of loose debris (such as pieces of duct tape, loose wire, broken glass, paper and herculite)
were retrieved from various, areas which otherwise were acceptably clean.
Loose items stored in containment were observed to be adequately secured to seismically-approved mounts or supports.
A portable welding machine was found attached
'to a steam generator support and was promptly relocated to an approved position.
Additionally, the pipe tunnel, reactor cavity, lower containment, and recirculation sumps were observed to be free of debris.
A s'mall number of valves were found with minor packing leaks as evidenced by boric acid buildup.
Those valves were documented and evaluated for repair through the initiation of Job Orders.
d.
The inspector observed a weekly surveillance test of 2AB Battery and reviewed procedure
- 12 flHP 4030 STP.013,
"Weekly Surveillance Test Procedure for Plant Batteries 1AB, 1CD, 2AB, 2CD." The technicians performing the test seemed knowledgeable of the system and all as-found data were within the required specifications..No major discrepancies were identified u.ith the procedure which appeared to adequately demonstrate OPERABILITY of 2AB Battery as outlined in the Technical Specifications.
No violations, deviations, unresolved or open items were identified.
h dl if'i i
t 70D>
The, inspector performed a selective review of electrical, and instrument and control request for change (RFC)
and minor modification (YiVi) design change packages.
The review verified that the design changes and modifications were in conformance with the requirements of the plant's Technical Specifications (TS),
CFR 50.59 (Safety Evaluation),
the Safety Analysis Report, and
CFR 50, Appendix B, Criterion III (Design Control).
The review also verified the adequacy of the installation and testing of the mod ificat ions.
~Desi n Review The following is a list of the modifications reviewed:
(I)
12-RFC-2382:
Eliminate Reactor Tri on RCP Breaker Indication This RFC eliminated the reactor trip which occurred when one out of four reactor coolant pump (RCP) breaker positions indicated open above permissive P-8 (515 reactor power).
The two out of four
anticipatory trip on open RCP breaker position indication above permissive P-7 (10K reactor power)
was unaffected by this modification'.
(2)
1-RFC-2887; Re lace Terry Turbine Overs eed Tri This RFC replaced the existing turbine driven auxiliary feed pump (TDAFP) electronic overspeed Air Pax trip device with a Dynalco trip device.
The Dynalco trip device is similar to the trip device installed on the emergency diesel generators.
The trip circuit was II II changed to an energ)ze to tr>p c>rcust so that a loss of power
~
wou ld. not interfere with the operation of the TDAFP.
Primary overspeed protection is provided by the mechanical overspeed trip device.
(3)
(4)
12-RFC-2902:
Narrow Ran e Accumulator Level Transmitters This RFC replaced the Barton narrow range'accumulator level transmitters with Foxboro transmitters.
12-RFC-3071:
Nuclear Instrument Drawer Circuitry Chan es (5)
(6)
This RFC replaced several preamplifier resistors in order to increase the sensitivity of the Unit 2 power range B nuclear instrumentation circuitry.
As a result of the decreased neutron leakage from the new core installed during the 1990 Uni't 2 refueling outage, the excore detector currents had decreased below the presently installed measurement capability.
This modification had been performed on the Unit 1 'nuclear instruments in 1985.
12-Hh-92:
Rod Position Indicator (RPI) Scale Chan cput This tifi replaced the existing RPI system meter scales with nonlinear scales that matched the RPI coil characteristics.
The scale replacement was intended to improve the accuracy of the RPI indications and thereby reduce the number of TS noncompliances.
12-lltl-110:
Rewire ESW and CCW Control Circuit (7)
This tiff corrected the drawing errors and subsequent wiring errors
'hat were made during the installation (1985 time frame) of Appendix R modifications.
2-fitl-132:
TSI Fire Wra Cable No. 2-12467 in Fire Zone
This MVi installed a one (1) hour fire wrap on Cable No. 2-12467 in Fire Zone 2 The following is a list of.the design control areas that were reviewed:
l diff'
i V if'i i ~lt i T~i 12-RFC-2382 X
X
=X X
1-RFC-2887 X
X, X
X 12-RFC-2902 X
X X
X 12-RFC-3071 X
X X
12-fjf1-92 X
X X
12-fjH-110 2-tlfi-132 X
X X
estions.
cklist)
a iat all durin the is now providing a written response to each of the checklist q
This provides the independent verifier (Design Verification CQ justification for the final design and will help in assuring t as ects of the desi n have been considered.
It was also note'd P
g design review that the design verifiers were questioning all aspects of the design.
This resulted in their comments having to be answered by the lead engineer prior to approval of the Design Verification Checl'list.
b.
Desi n
Im lementation The desiqn review determined that the licensee was adequately controlling the design process, and was meeting applicable regulatory requirements and design bases.
The inspector observed a significant improvement in the area of design verification.
In the past, the Final Design Report.
Checklist questions were answered with'
checl off or not applicable responses without providing justification for the response.
The licensee The following modifications resulted in the generation of condition reports:
( 1)
During the review of 1-RFC-2887, the inspector reviewed the procedures that were used to adjust the 250Vdc N-Train batteries equalization voltage.
The two N-Train batteries are normally 120 cell batteries.
The licensee had performed modification 12-AM-25 which removed three cells from each battery.
Surveillance test procedure No. 2tiHP4030.STP.045 (Revision 4), "Quarterly Surveillance Test Procedure for 2N Hattery," did not reflect the current 117 cell arrangement.
However, the electrical maintenance personnel were cognizant that the battery arrangement was 117 cells.
In addition, the equalization voltage had been properly adjusted for a 117 cell battery.
The licensee initiated Condition Report No. 90-0075 to determine why the procedure had not been changed to reflect a
117 cell battery.
The inspectors have no further concerns on this item at this time.
C (2)
During the walkdown of 12-HH-110, the inspector noted that the wiring changes that were made in the Unit 2 West Essential Service Water (2-PP-7M) control circuitry were wired with 16 AWG wire.
The wires were connected between the 250Vdc bus fuses (100A) and the low header pressure isolation relay fuses (10A).
The wire size was not specified in 12-flH-10 because the wiring changes only involved the retermination of the wires to a different terminal.
Control and relay panel wiring specification DCCIC-108-gCN states, in part, that unless otherwise specified, the wire shall be No.
AWG 7-strand, single conductor, 600 volt, 90'C insulated wire.
The licensee indicated that the two wires were probably installed during Appendix R
ESW control circuit wiring activities performed in 1985.
The
AWG wire is of an adequate size to supply power to the isolation relay (current drain is 30 mA); however, this is not a recommended installation.
The 100A supply fuse does not protect the wire.
The licensee initiated Condition Report No. 90-0073 to investigate the wire size discrepancy and committed to replace the wires during the Unit 2 1992 refueling outage.
The inspectors have no further concerns on this item at this time.
Other than the items noted above, the licensee was adequately controllirg the implementation packages, testing and installation work for the modifications reviewed.
In addition, the licensee has formed a
Hodification Test Group with an overall responsibility to assure-adequate post modification testing is performed.
The testing requirements specified for modification 12-RFC-2887 were reviewed and were found to be acceptable.
No violations, 'deviations, unresolved, or open items were identified.
7.
Enqineerin and Technica I Su ort The inspector monitored engineering and technical support activities at the site and, on occasion, as provided to the site from the corporate office to assess the adequacy of the engineering and technical support to other parts of the organization such as operations, maintenance, and outage management.
a.
On December 18, 1990, during a walkdown of Unit 2 containment in preparation for Unit 2 mode change from HODE 2 to HODE 1, the licensee noticed that, unlike the adjacent recirculation sump, the lower containment sump was not protected by a wire cloth fabric.
Although the existing configuration on both sumps was in accordance with approved design drawings, because the lower containment sump is cross-connected to the recirculation sump, there was a concern that particles capable of clogging the spray heads of the containment spray system would enter the recirculation sump from the lower containment sump.
In order to preclude this possibility the licensee instaileu a fine mesh tn prevent such material I iarper than 1/4-inch) from entering the lower containment sump.
Additionally, a walkdown of Unit 1 containment found a similar situation with the Unit ) lower containment sump.
The installation of the fine mesh was completed for Unit 2 on December 19, 1990 and for Unit
on December 22, 1990 under minor modification 12-HH-175.
The design of the recirculation and lower containment sumps provides an 8-inch pipe and a flow path between the two sumps:
During normal operation, any water that may accumulate in the recirculation sump will drain to the lower containment sump and be processed by the waste disposal system.
During a loss-of-coolant accident, water that is spilled from the break, injected by the containment spray system, or created by ice melt, spills to the lower containment floor.
This water would first flow to the lower containment sump and pass through the 8-inch cross-connect, thereby filling the recirculation sump until the water level reaches the height of the inlet to the recirculation sump.
If some debris exists in containment, the current design of the lower, containment sump inlet without the fine mesh screen could al'low the debris to flow back into the recirculation sump via the 8-inch pipe connecting the two sumps.
The licensee's current analysis assumes that no material: larger than I/O inch enters the containment spray system.
This limit ensures that containment spray nozzles 'do not become plugged during spray system operation.
b.
The licensee completed replacement of the divider barrier seal made of Uniroya 1 -3807 in Unit I containment with Uniroyal 41300.
Divider barrier seals for both Units were declared inoperable on August I, 1990, because cracks in the Unit 2 seal were found duri'ng the performance of "Containment Divider Barrier Seal Inspection,"
OHP n030 STP.249 (see Inspection Report 50-315/90021(DRP);
50-316/90021(DRP)).
The divider 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 bar rier 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.
Ho violations, deviations, unresolved or open items were identified.
8. S~tlll07)
Routine facility security measures, including control of access for vehicles, packages and personnel,,i<ere 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.
a, Two "Fitness-For-Duty" concerns were reported to the NRC this inspection period.
On January ll, 1991, an individual was apprehended by the licensee's security force while attempting to enter the Protected Area with a blood alcohol content (BAC) above the
.0.04 percent limit. The individual was stopped before access was oranted and placed on the ineligibility list for access in accordance with the licensee's procedures.
A second individual was also
apprehended on January 16, 1991.
At the time of apprehension, the-individua'1 has been on site for less than two hours.
The individual's wo'rk activities while or site were reviewed and no significant safety concerns were identified.
The individual's access was likewise suspended.
A full description of,.both events was given to the NRC Region III Security staff for follow-up.
b.
A routine safeguards inspection was conducted by a.security specialist from the NRC Region III Office from January 7-11, 1991, involving management support,'.protected and vital area control, security equipment maintenance and testing, and other areas.
The inspection, documented in NRC Inspection Report 50-315/91002(DRSS);50-316/91002(DRSS),
found the lice'nsee to be in compliance with NRC requirements in the areas examined.
No violations,'eviations, unresolved or open items were identified.
9.'e ortable Events(92700 92720)
The inspector reviewed the following Licensee Event Reports (LERs) by means of direct observation, discussions with licensee personnel, and review of records.
The review addressed compliance to reporting requirements and, as applicable, that immediate corrective action and appropriate action to prevent recurrence had been accomplished.
a ~
b.
(Closed)
Licensee Event Report (316/88001-LL):
On January 6,
1988 at 1:10 p.m., the licensee discovered an incorrect sample valve lineup for VRS-2500, Unit 2 auxiliary building vent radiation monitor.
Consequently; continuous monitoring for noble gas was not performed pe~
Technical Specification 3.3.3.10, Table 3.3-13, Section 3a.
from December 30, 1987 to January 6,
1988.
The cause was personnel error.
The chemistry technician did not restore the valves to their normal alignment after obtaining a weekly grab sample from VRS-2500, per procedure
THP 6020 LAB.135.
The technician involved has been counselled on proper procedure compliance.
Changes to both 2 THP 6020 LAB.135 and
THP 6020 LAB.135 were written to require local independent verification of proper valve alignment, in addition to requesting control room personnel to verify the monitor has been returned to operation.
This item is closed.
(Closed)
Licensee Event Report (316/89001-LL):
On January 25, 1989, the licensee discovered that controls to limit access to a
non-lockable extreme high radiation area at the bottom of the refueling transfer canal had not been implemented during the period of drainage, December 20-27, 1988.
The cause of this event was personnel error.
Radiation Protection access to the transfer canal, had been made.
Radiation Protection failed to verify that positive controls had been implemented.
A design change, approved by plant management, has been implemented to provide a means of locking this area.
This item is closed.
(Closed)
Licensee Event Report (316/89002-LL):
On August 17, 1988, a
seismic restraint, located on the 24 inch Emergency Core Cooling System suction line from'nit 2 Refueling Water Storage Tank, was identified as having significant deformation.
Subsequent walkdown of the subject piping system revealed additional design inconsistencies of two adjacent supports.
The licensee believes the deformation most likely occurred during the removal and installation of the piping: during/following initial plant start up activities.
A revised design was developed to reinforce the restraint and return the gap clearances to the original seismic design requirements.
Repairs and the visual inspection for final acceptance have.been completed.
The two adjacent supports were redesigned and subsequent modifications have been completed.
The licensee has determined that this event is not reportable and has retracted this LER.
This item is closed.
(Closed)
Licensee Event Report (316/89008-LL):
On March 11, 1989 at 6:31 a.m.,
the licensee identified that the automatic carbon dioxide (C02) actuation system (EIIS/LW) for the reactor cable tunnel quadrants one:, three, and four, had been isolated since 4:03 a.m.,
a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and 20 minutes, without the required firewatches.
This event was caused by a worn key.
The key lock switch is for personnel safety during access.
The switch is designed such that the key can only be removed if the switch is either in the normal or the isolate position.
The worn key could be removed prior to.
being in the full normal position.
This was far enough to operate the first set of contacts for the local indicating lights but not the contacts for the automatic actuation circuitry and the control room alarm annunciators.
The key was replaced and the Safety and Assessment Department has instituted a policy of replacing all of their C02 key -lock switch keys on a periodic basis.
This item is closed.
(Closed)
Licensee Event Report (316/89014-LL):
On August 14, 1989 at 4:01 p.m.,
a Reactor Protection System (RPS) actuation (reactor trip)
occurred when operators transferred the control room instrumentation distribution (CRID) IV vital bus inverter to its normal power supply and the inverter failed.
The cause of this event was a faulted SCR in the GRID IV inverter static switch circuitry.
This resulted in a very low output voltage resulting in 'a reactor trip caused by a reactor coolant pump breaker indicating open.
The GRID IV inverter has been repaired and tested operable.
All components powered from the GRID IV were evaluated for damage and repaired/tested as necessary to verify operability.
Instrumentation and Control has developed a guideline for checkout of a CRID inverter
to verify the inverter and static switch are operating correctly if a CRID inverted auto-transfers to its backup power supply.
This item is closed.
(Closed)
Licensee Event Report (316/89015-LL):
On August 21, 1989, an inoperable open fire damper was found for which the action statement requirements=of Technical Specification 3.7.10 had not been implemented.
This event was caused by pers'onnel and procedural error.
During the development of a Task Sheet for preventive maintenance on dampers not subject to the Technical Specification, some Technical Specification dampers were incorrectly included.
The damper was identified for repair on July 18, 1989, by maintenance personnel using the preventive maintenance Task Sheets.
The Tasl Sheets have been thoroughly reviewed and revised to delete from maintenance inspection those dampers covered by Technical Specification 3.7. 10.
All dampers deleted were verified as being covered by an existing guality Control procedure.
This item is closed.
(Closed)
Licensee Event Report (316/9003-LL):
On February 14, 1990, the licensee identified that th'e purge valve for the lower containment train 8 Special Particulate, Iodine, Noble Gas (SPING)
monitor sample chamber, was open during operation of the monitor.
This prevented the required channels (Channel 1 - beta particulate, Channel 5 - low range noble gas)
from fulfillingthe requirements of Technical Specification Table 3.3-3.
This event was caused by a faulty logic circuit in the SPING start up process from a no power condition.
When power is applied to the microprocessor, the purge valve begins to open before a logic relay interrupts the power to that particular circuit.
The operating procedure, for the radiation monitoring system, was revised to reouire a
"FLUSH" command whenever any SPING monitor is returned to service.
The
"FLUSH" command cycles the purge valve fully closed.
This item is closed.
No violations, deviations, unresolved or open items were identified.
10.
Review of Alle ations (Closed) Allegation No.
RI I I-90-A-0105.
On October 17, 1990, an allegation was received by Region III regarding maintenance activities at the D.
C.
Cook plant.
The allegation was divided into the following four issues.
There is no planning and scheduling of maintenance activities, resulting in confusion among personnel within the department.
Also; scheduling was,not done by the fiaintenance Department, but was done by the Outage t1anagement Team.
Review of planning and scheduling of maintenance activities by the inspector disclosed that the licensee was having some problems in this area during the Unit 2 refueling outage which started June 30, 1990.
Reduced to simple terms, part of the problems dealt with the inability of two (Maintenance Department and Outage Management Tean)
computer systems used for scheduling to communicate with each other.
However, the problems were corrected by the end of the Unit 2 outage and by the beginning of the Unit I outage which starte'd on October 19,
-1990.
There was no indication that a breakdown occurred in the planning and scheduling of maintenance activities that was of any safety significance.
Further, it is not unusual for an Outage Management Team to take control of all scheduling during a refueling outage.
l>hi le some of part "a" of this allegation was substantiated, it was of no safety significance.
Planning and scheduling of maintenance by the Outage Management Team directly contributed to the cause of the July 13, 1990; electrocution event.
This was subsequently revised to "If the planning would have been done by an electrical planner rather than an ISC planner, the event would'ot have occurred."
The inspector reviewed the licensee, VRC, and Michigan Department of Labor, Bureau of Safety and Regulation (MIOSHA) reports for this event and interviewed various plant personnel..
It is the practice of the licensee for worg on current transformers in this event)
to be performed by ISC rather than the ele department
.
As such, planning is done by ISC planners.-
normal (the case trical The allegation that "If the planning would have been done by an electrical planner...the event would not have occurred,"
could not be substantiated.
There has been a degradation in quality of some maintenance workers attituaes, and they iust "did what they were told" resulting in reduction of the quality of work perfor'med.
Observation of maintenance during the followup maintenance team inspection (Inspection Report thos.
50-315/90024; 50-316/90024)
by NRC Regional inspectors and by resident inspections during the back-to-back refueling outages in 1990 found the quality of maintenance and workers attitudes to be acceptable.
The allegation could not be substantiated.
Maintenance managers were not following department policies and instructions on conduct of maintenance and their alleged noncompliance with their standard operating practices created confusion amongst the workers and some maintenance supervisors.
Evaluation of the practices of maintenance managers by the inspector and by the resident inspectors during the back-to-back refueling outages identified neither occurrences of noncompliance with standard operating practices nor confusion amongst the workers.
This allegation could not be substantiated.
"S
'
No violations were identified and Allegation No. RIII-90-A-0105 is
'onsidered closed.
No violations, deviations, unresolved or open items were identified.
11.
Mana ement tleetin (30702)
A management meeting, attended as indicated in Paragraph l.a was conducted at the Region III office on February 1, 1991.
The purpose of the meeting was to discuss the progress of and observations from various licensee initiatives and programs.
The topics presented by the licensee staff were:
1.
D.
C.
Cook Maintenance Department 1991 Goals 2.
Lessons Learned from'Unit 1 Refueling Outage 3.
AEPSC Engineering Activities to address NRC ESH SSFI Design Verification Concerns and discussion of future programs and equipment upgrades which involved significant corporate and plant enoineering and design input and coordination.
4.
Status of Piping Design Confirmation Program 5.
Results of RHR Heat Exchanger
"As-found" Analysis 12.
liana ement Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1.b)
on February 7,
1991, and held a telephone discussion on February 13, 1991, 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.
17