IR 05000315/1988012
| ML17326B382 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 05/06/1988 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17326B380 | List: |
| References | |
| 50-315-88-12, 50-316-88-14, NUDOCS 8805240012 | |
| Download: ML17326B382 (27) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/88012(DRP);
50-316/88014(DRP)
Docket Nos. 50-315; 50-316 Licenses No. DPR-58; DPR-74 Licensee:
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, Br idgman, Michigan Inspection Conducted:
March 15 through April 25, 1988 Inspectors:
B. L. Jorgensen
'
J.
K. Meller B.
W. Stapleton C.
F. Gill Approved By:
B.
.
urg s, Chief Reactor Projects Section 2A Date Ins ection Summar Ins ection on March 15 throu h A ril 25, 1988 Re orts No. 50-315/88012 DRP; o.
- 16
~d:
l dl p
l by b
ld of:
actions on previously identified items; operational safety verification; radiological controls; maintenance; surveillance; fire protection; security; outages; quality programs, and reportable events.
In addition, an enforcement conference and a management meeting were conducted.
Results:
Of the ten areas inspected, one violation (Level IV, fai lure to
~per crm required chance}
checks - Paragraph 11} was identified in cne area, and none were identified in the remaining nine areas.
SS052400i2 SS0510 PDR ADOCK 05000315
DETAILS 1.
Persons Contacted a.
Ins ection Conducted March 15 throu h A ril 25, 1988
- W. Smith, Jr., Plant Manager
"A. Blind, Assistant Plant Manager - Administration J. Rutkowski, Assistant Plant Manager - Production
- L. Gibson, Assistant Plant Manager - Technical Support
- B. Svensson, Licensing Activity Coordinator K. Baker, Operations Superintendent
- J. Sampson, Safety and Assessment Superintendent E. Morse, guality Control Supervisor'.
Beilman, I&C/Planning Superintendent J. Droste, Maintenance Superintendent T. Postlewait, Technical Superintendent
- Engineering L. Matthias, Administrative Superintendent M. Horvath, guality Assurance Supervisor D. Loope, Radiation Protection Supervisor 8S.
Brewer, Radiological Support Section Manager-AEP PS.
Klementowicz, SGRP Project Health Physicist-AEP The inspectors also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
- Denotes some of the personnel attending Management Interview on April 27, 1988.
PDenotes personnel attending a separate Management Interview regarding the SGRP radiation protection program on April 27, 1988.
b.
Enforcement Conference - March 17, 1988 (I)
Licensee D. Williams, Jr., Senior Executive Vice President Engineering and Construction, AEPSC M. Alexich, Vice President-Nuclear Operations, AEPSC T. Ar genta, Manager, Construction Engineering Division (Electrical),
AEPSC P. Barrett, Manager, Nuclear Safety and Licensing, AEPSC R. Carruth, Manager, Electrical Generation Section, AEPSC R. Kroeger, Manager, guality Assurance, AEPSC R. Shoberg, Assistant Section Manager, Instrument and Control, AEPSC M. Horvath, Site gA Supervisor, AEPSC J. Anderson, EGS-N, Cognizant Engineer, AEPSC K. Munson, EGS-N, Electrical Engineer, AEPSC W. Smith, Jr., Plant Manager J.
Sampson, Safety and Assessment Superintendent
(2)
Nuclear Re ulator Commission C. J. Paperiello, Deputy Regional Administrator H. J.
Miller, Director, Division of Reactor Safety M. J. Virgilio, Acting Deputy Director, Division of Reactor Projects W.
G. Guldemond, Chief, Reactor Projects Branch
R.
N. Gardner, Chief, Plant Systems Section B. L. Burgess, Chief, Reactor Projects Section 2A B. L. Jorgensen, Senior Resident Inspector D. S. Butler, Plant Systems Section Inspector c.
Mana ement Meetin
- A ril 6 1988 (I)
Licensee and Contractor L. Gibson, Assistant Plant Manager-Technical Support T. Harshbarger, Project Licensing - AEPSC
'.
Brewer, Radiological Support Section Manager - AEPSC R. Rickman, ISI Supervisor J. White, Site Project Manager, SGRP - AEPSC A. Walcutt, Project guality Assurance Manager - M-K. Ferguson B. Barrick, Steam Generator Project gA Section - AEPSC S.
Hodges, Project Engineer - AEPSC J. Felder, equality Assurance
- AEPSC (2)
Nuclear Re ulator Commission A. B. Davis, Regional-Administrator C. J. Paperiello, Deputy Regional Administrator H. J. Miller, Director, Division or Reactoi Safety W. G. Guldemond, Chief, Reactor Projects Branch
B. L. Burgess, Chief, Reactor Projects Section 2A J. J. Harrison, Chief, Engineering Branch J.
K. Heller, Resident Inspector, D.
C.
Cook C. F. Gill, Senior Radiation Specialist D. H. Danielson, Chief, Material and Processes Section W.
C. Liu, Reactor Inspector, Division of Reactor Safety R.
Kazmar, Project Inspector, Division of Reactor Projects R. J. Farber, Reactor Inspector, Division of Reactor Projects B. Azab, Reactor Inspector, Division of Reactor Safety 2.
Actions on Pr eviousl Identified Items a ~
(Closed) Violation (315/87003-02):
Motor operated valves in the containment spray system were not tested immediately after packing adjustment.
The licensee's response (AEP:NRC:1025) dated March 23, 1987, discussed the violation, the corrective action taken and the results achieved.
The inspector has verified the licensee's response and has no additional question b.
c ~
d.
e.
(Closed) Yiolation (315/87003-03):
Acceptance criteria for the Component Cooling Water (CCW)
pumps was not conservative with respect to the Technical Specification acceptance criteria.
The licensee's response (AEP:NRC:1025) dated March 23, 198?, discussed the violation, the corrective action taken and the results achieved.
The CCW nonconservatism was corrected and found to also exist in the Essential Service Water (ESW) system test procedure, which was also corrected.
The licensee's evaluation determined that ESW pump performance had not degraded.
However, as a result of the new acceptance criteria, the licensee found that the containment spray heat exchanger performance was degrading due to biofouling.
This was corrected by chemical flushing.
(Closed) Violation (315/87011-01; 316/87011-01):
Weld rods were not properly disposed of at the end of the shift.
The licensee's response (NRC:AEP: 1032) dated July 29, 198?, discussed the violation, the corrective action taken and the results achieved.
The inspector has verified the response and has no additional questions.
(Closed)
Unresolved Item (315/86041-01):
The West containment spray train was inoperable while the other train was untested following maintenance.
This unresolved item was reissued as a violation (315/87003-02)
which is discussed in Item a.,
above.
(Closed)
Open Item (315/87004-01):
A valve was found chained and locked closed whereas the valve lineup sheet identified the valve simply as closed.
The valve lineup sheet was changed to reflect the chain and lock.
The NRC Region III Division of Reactor Safety, Operational Programs Section has reviewed the D.
C.
Cook Open Item List and determined that the items listed below can be administratively 'closed because they duplicate items addressed in IE Bulletin 85-03.
This determination is documented in a February 23, 1988, memorandum from M. P. Phillips, Chief, Operational Programs Section to N. J. Chrissotimos, Deputy Director, Division of Reactor Safety.
(Closed)
Unresolved Item (315/86011-01; 316/86011-01):
Inadequate design control of Limitorque valve operator limit and torque switch setting.
(Cl osed)
Unresolved Item (315/86011-02; 316/86011-02):
Inadequate testing to assure motor operated valve operability during plant life.
h.
(Closed)
Open Item (315/86011-03; 316/86011-03):
Licensee needs to initiate periodic valve inspection and preventive, maintenance program.
(Closed)
Open Item (315/86011-04; 316/86011-04):
Testing needs to be specified to assure motor operated valve'operability after valve packing adjustment j.
(Closed)
Open Item (315/86011-05; 316/86011-05):
Motor operated valve maintenance procedures need to be revised.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Verification 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.
Evaluation, corrective action, and response for off normal conditions or events, if any, were examined.
This included compliance to 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.
Unit 1 operated routinely at its administrative power-level of 90-percent throughout the inspection period with a single brief outage (see Paragraph 9, "outages") to perform routine required ice condenser surveillance testing.
b.
Unit 2 operated at its administrative power level of 80-percent throughout the period until beginning a scheduled extended outage (see Paragraph 9, "outages")
on April 23, 1988.
c ~
d.
On one tour of the plant (2E auxiliary feed pump roam)
on April 13, 1988, the inspector found three plastic valve seals, serially numbered 0005351 through 0005353.
The inspector verified these were spare seals by reviewing the controlled seal log and status board.
The Shift Supervisor was then notified and he had the spares picked up and returned to his office where spares are normally kept.
The inspector noted Control Room Log entries describing "entry into Technical Specification 3.0.3" (one for each Unit) on March 25.
The Unit 1 entry turned out to be in error - the correct containment integrity Technical Specification was also referenced.
The inspector verified complianc The Unit 2 entry involved a check valve flow test performed quarterly per ASME Section XI.
The inspector reviewed the associated test procedure,
- 12-OHP SP.057,
"Residual Heat Removal Section Check Valve Stroke Test", Revision 0, October 21, 1986.
In essence, the procedure verifies the flow capability of RHR suction check valve SI-148.
The specified minimum flow is 200 gpm.
The flow path available in plant design (which predated Section XI) is recirculation to the Refueling Water Storage Tank (RWST) via a pair of normally locked closed manual valves (RH-130 and RH-117) in an 8 inch line.
The-inspector found appropriate precautions and controls in the procedure to minimize the potential associated with postulated accidents which might occur during the test when the manual valves, which would "steal" injection flow from both trains, are cracked open.
Loss of over 300 gpm via recirculation to the RWST is not specifically analyzed; thus, Technical Specification 3.0.3 applies if (in adjusting the large manuaI valves to obtain flow greater than 200 gpm) flow momentarily exceeds 300 gpm.
The inspector was also provided with and reviewed internal licensee memoranda concerning this test, which demonstrated a proper review of and concern for how to accomplish the required testing with minimum potential adverse impact.
A Unit 2 "Unusual Event" was declared at 4:35 p.m.
on April ll, 1988, when the Turbine Driven Auxiliary Feedwater Pump (TDAFP) and one of the two Motor Driven Auxiliary Feedwater Pump (MDAFP) were simultaneously inoperable.
The TDAFP was tripping on overspeed, and the MDAFP had no emergency electrical power supply because its associated diesel generator was believed to have water contamination in its fuel oil storage tank.
The licensee took appropriate actions in declaring the Unusual Event when commencing the required Unit power reduction.
The event and power reduction were terminated at 6:32 p.m. after the fuel oil storage tank had been verified water free.
Subsequently, the inspector pursued the matter in more detail via review of the associated logs and, other documents.
The Unit 2 Control Room Log for April 11, 1988, and Condition Report 2-4-88-0514 document the circumstances for inoperability of the two Auxiliary Feedwater Pumps (AFP).
The applicable log entries are:
1028 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.91154e-4 months <br /> 1435 hours Attempted to start Turbine Driven (TD) AFP, tripped on mechanical overspeed, TDAFP has been inoperable since 0847, Technical Specification 3.7. 1.2 Action a.,
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
2-CD Diesel Generator inoperable due to water in the fuel oil storage tan hours 1832 hours0.0212 days <br />0.509 hours <br />0.00303 weeks <br />6.97076e-4 months <br /> Started power reduction in accordance with Technical Specification 3.0.5 (TDAFP inoperable and emergency power source to "E" Motor Driven (MD) AFP inoperable).
Enter Unusual Event per ECC-13.
CD Diesel Generator operable,
"E" MDAFP emergency power source operable.
Exited Technical Specification 3.0.5 and Unusual Event.
The 1435 log, entry was due to a non-representative sample.
Subsequent samples of both diesel storage and day tanks showed water content to be within specification.
The inspector reviewed the 1615 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.145075e-4 months <br /> log entry reference to Technical Specification 3.0.5, which discusses inoperability of a component solely due to its emergency power supply being unavailable.
The inspector concluded this was not the correct Technical Specification.
In this case, Technical Specification 3.7.1.2.a requires each OPERABLE MDAFP to be capable of being powered from its emergency power supply.
Since one MDAFP was inoperable (not capable of being powered from its emergency power supply)
and the TDAFP was also inoperable (overspeed trip problems), it appears that ACTION b. of Technical Specification 3.7. 1.2 (two auxiliary feedwater pumps inoperable)
was applicable.
The difference between Technical Specifications 3.0.5 and 3.7.1.2 ACTION b. is the duration of time available to MODE 3.
Technical Specification 3.7.1.2 ACTION b. is more restrictive by two hours.
Fortunately both specifications were met.
This item was discussed with the NRR Project Manager, and members of the plant staff, and at the Management interview.
No violations, deviations, unresolved or open items were identified.
4.
Radiolo ical Controls 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.
Effluent releases were routinely checked, including examination of on-line recorder traces and proper operation of automatic monitoring equipment.
Independent surveys were performed in various radiologically controlled areas.
a ~
The inspector attended meetings among licensee and NRC Region III representatives on March 16, 1988, for discussion and clarification of items contained in the licensee's radiation protection action plan.
The discussions served primarily to ensure a
common understanding of the nature and extent of plan "Action Items" and to provide the current status of the items.
NRC Region III will continue to follow and report on these matter hours
1832 hours0.0212 days <br />0.509 hours <br />0.00303 weeks <br />6.97076e-4 months <br /> Started power reduction in accordance with Technical Specification 3.0.5 (TDAFP inoperable and emergency power source to "E" Motor Driven (MD) AFP inoperable).
Enter Unusual Event per ECC-13.
CD Diesel Generator operable,
"E" MDAFP emergency power source operable.
Exited Technical Specification 3.0.5 and Unusual Event.
The 1435 log entry was due to a non-representative sample.
Subsequent samples of both diesel storage and day tanks showed water content to be within specification.
The inspector reviewed the 1615 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.145075e-4 months <br /> log entry reference to Technical Specification 3.0.5, which discusses inoperability of a component solely due to its emergency power supply being unavailable.
The inspector concluded this was not the correct Technical Specification.
In this case, Technical Specification 3.7. 1.2.a requires each OPERABLE MDAFP to be capable of being powered from its emergency power supply.
Since one MDAFP was inoperable (not capable of being powered from its emergency power supply)
and the TDAFP was also inoperable (overspeed trip problems), it appears that ACTION b. of Technical Specification 3.7 ~ 1.2 (two auxiliary feedwater pumps inoperable)
was applicable.
The difference between Technical Specifications 3.0.5 and 3.7. 1.2 ACTION b. is the duration of time available to MODE 3.
Technical Specification 3.7. 1.2 ACTION b. is more restrictive by two hours.
Fortunately both specifications were met.
This item was discussed with the NRR Project Manager, and members of the plant staff, and at the Management interview.
No violations, deviations, unresolved or open items were identified.
4.
Radiolo ical Controls 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.
Effluent releases were routinely checked,'ncluding examination of on-line recorder traces and proper operation of automatic monitoring equipment.
Independent surveys were performed in various radiologically controlled areas.
a.
The inspector attended meetings among licensee and NRC Region III representatives on March 16, 1988, for discussion and clarification of items contained in the licensee's radiation protection action plan.
The discussions served primarily to ensure a common understanding of the nature and extent of plan "Action Items" and to provide the current status of the items.
NRC Region III will continue to follow and report on these matter During an auxiliary building tour on March 29, 1988, the inspector attempted to open the high radiation door to the spent fuel skimmer room without using the card reader (an approved locking mechanism for high radiation doors).
Due to a door latch malfunction, each attempted entry was successful.
The latch failure was identified to a radiation protection technician, who promptly secured the door with a lock and chain and issued a Job Order.
Positive control of high radiation areas is a requirement of PMP-6010 RAD.002 "Entry Into High Radiation Areas".
Compliance to the procedure is, in turn, a requirement of'echnical Specification 6.8. l.a.
The inspector discussed this event with specialists in NRC Region III, and reviewed the apparent violation against criteria of the NRC Enforcement Policy as stated in 10 CFR Part 2, Appendix C.
The focus was on whether this problem (latch failure) was due to a fault in licensee "control".
A review of Job Orders and the door maintenance log showed that the door does not have a documented failure history.
Further, there was no evidence that the licensee should have known that the door latch had failed.
As such, a Notice of Violation concerning procedure RAD.002 is not being issued.
The inspector routinely monitored licensee efforts to evaluate and minimize instances of personnel contamination.
As of April 26, 1988, a total of 33 personnel contamination events had occurred for calendar year 1988.
Review of records for the first four months of 1987 shows the frequency of personnel contamination events has been reduced by a factor of approximately four.
Both Units have been at power for 1988, however, whereas during the same time frame in 1987 each Unit had completed an unplanned maintenance outage.
An NRC/Region III Senior Radiation Specialist met with members of the Project Radiological Protection/ALARA Group (PRPAG),
and others, on April 20-22, 1988 at the D. C.
Cook plant.
Also, tours were conducted of Steam Generators Repair Project (SGRP) facilities, including those in the mockup training center and the containment access, radioactive material loading, steam generator storage, and security access buildings.
The purpose of the site visit was to review PRPAG readiness to provide adequate RP support to the SGRP.
The key PRPAG personnel are onsite including some radiation protection technicians (RPTs).
The proposed schedule for arrival and training of RPTs and radwaste technicians (RWTs) was compared to the SGRP task schedule; no significant problems were noted.
Interviews and reviews of selected resumes indicate that the key PRPAG positions are occupied by well qualified personnel.
However, the proposed ratio of senior to junior RPTs and the acceptance criteria for RWTs appeared weak.
In response to these concerns, the licensee stated that the technicians (junior RPTs and RWTs) would not be given assignments unless they were qualified by the licensee's training program for those tasks.
Although the lesson plans were not ready for review, discussions with PRPAG personnel indicated that technician and craft contract worker training should be thorough and comprehensiv In addition to PRPAG,interviews, discuss'ions were held with SGRP, site, and corporate gA managers, and with personnel who interface daily with the PRPAG, including the contractor (MK-F) ALARA Supervisor and the Plant Radiation Protection and ALARA Supervisors.
The RP/ALARA coordination during the current preparational stage of the project appears adequate, primarily because of daily coordination meetings; however, the informality of much of the coordination effort has the potential to be less effective as the SGRP work intensifies.
In response to this concern, the licensee stated that the PRPAG management would increase the oversight of the coordination activities (including evaluations by consultant personnel who are not assigned to the SGRP),
and that any shortcomings in PRPAG performance would be immediately corrected upon identification (including possibly reorganization, personnel changes, and budget adjustments).
Also, more gA audit and surveillance attention than originally planned would address the adequacy of PRPAG work activities, coordination between the PRPAG and other project and plant organizations, and project/plant interfaces regarding RP job-coverage and ALARA activities.
The facilities and equipment plant tours indicate that the PRPAG should be able to adequately support the scheduled SGRP work activities.
The facilities are of adequate size and most of the essential RP related equipment and instrumentation is onsite or is expected onsite in the near future.
Access control facilities and provisions for radwaste disposal appear to be well designed with adequate flow paths.
The number and type of RP equipment and instrumentation, including the dose tracking/access control and radwaste tracking computer systems, appear adequate and should represent a significant upgrade of the plant RP program upon completion of the SGRP.
The TLD facility is well stocked with dosimetry, readers, and calibration equipment.
The project has developed an apparently comprehensive TLD gA/gC program, including onsite g1ow curve computer and interlaboratory comparisons.
The licensee expects NVLAP accreditation of the project TLD (Panasonic)
program in early March 1988.
The rest of the PRPAG procedures are also expected to be approved in early March 1988; a selective review of the procedures and discussions with PRPAG personnel revealed no significant problems.
Interviews, plant tours, and procedural review indicate that the licensee has developed an effective program to provide radiation protection support of the Steam Generator Repair Project.
During the site visit, the licensee was cooperative and responsive to NRC concerns.
The concerns addressed above, and others, were promptly addressed by the licensee.
This site visit was restricted to the
'eview of the licensee's readiness to provide adequate RP support to SGRP, considering the fact that the licensee is still essentially in the planning stages.
Further inspections during the upcoming SGRP outage will be necessary to determine how effectively the licensee implements the SGRP radiation protection/ALARA pla One violation (not cited)
and no deviations, unresolved or open items
~
~
~
were identified.
5.
Maintenance 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 735282 repair of body-to-bonnet leak on valve 1-DRV-322 b.
Job Order JO 731726 repair of packing leak on valve 1-DRV-341 Each of the above was performed utilizing licensee procedure
""12 MHP 5021.001.012
"Maintenance of Hammel Dahl V500 Series Globe and Angle Design Valves", which the inspector also reviewed.
C.
On March 20, 1988 the resident inspector office received information from the NRC Region III office pertaining to the improper use of Furmanite in containment isolation valves.
This information was provided to the Maintenance Department as follow 'up to maintenance activities (including use of Furmanite) pertaining to steam generator blowdown isolation valves (Inspection Report 50-315/87031; 50-316/87031).
No problems pertaining to the improper use of Furmanite were identified.
d.
On March 30, 1988, with both Units in power operation, the licensee learned from Limitorque Corporation that a torque switch design currently in some safety related Model SMB-00 motor operators had not been qualification tested.
During the first few years of production of Model SMB-00 motor operators, some were equipped with a torque switch of an earlier design rather than the "FIBRITE" switch subsequently qualified per 10 CFR 50.49.
The unqualified switches are brown in color like the "FIBRITE" switch which is now standard, but they are identifiable by what appears to be a
laminated phenolic material used in the body of the switch and for the dielectric.
Forty-two valves in Unit 1 and thirty-nine in Unit 2 were affected.
The licensee prepared a Justification for Continued Operation (JCO)
dated March 31, which the inspector reviewed on April 1, 1988.
The purpose of the immediate inspector review was to identify any potential cases where compensatory actions credited in the analysis appeared impracticable.
In selected instances, the inspector toured the areas involved to verify, for example, that valves needing operator manipulation were equipped with reach rods if they were going to be in a 'severe radiological environment.
No invalid assumptions or. claims were noted in this limited review.
The JCO is undergoing a more comprehensive analysis by the Office of Nuclear Reactor Regulation.
Pending a determination on the acceptability of the installed valve/torque switch assemblies for the period contemplated in the JCO, this matter is considered an Unresolved Item (315/88012-01; 316/88014-01).
One unresolved item and no violations, deviations, or open items were identified.
6.
Surveillance 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.
Observed
- 12 THP 4030 STP.204
"Personnel Airlock Leakage and Interlock Surveillance Test" performed on Unit 2 upper airlock on April 18, 1988 and Unit 2 lower airlock on April 19, 1988.
b.
Reviewed
- "12 THP 4030 STP.204'erformed March 1 - 3, 1988 and September
4, 1987 for Unit 1 and October 4 - 5, 1987 for Unit 2.
The inspector found the current revision of STP.204 (Revision
dated April 14, 1988) to be well organized and easy to follow. It appears to implement the applicable sections of Technical Specification 4.6. 1.2.3 and of 10 CFR 50, Appendix J.-III.D.2.B.cc.
The inspector discussed his comparison of STP.204 and the vendor manual with the responsible site engineer.
i)
STP.204 has clamps installed on the outer airlock door during the performance of the airlock pressurization test.
The vendor manual is silent on use of the outer airlock door clamps during
performance of the test.
The engineer stated that this practice had been discussed with the vendor (W. J.
Wooley) who stated that the clamps would not affect the test outcome.
ii)
STP.204 specifies a door clamp bolting force of 50 lb-ft, whereas the vendor manual specifies a force approximately seven times greater.
The engineer was able to produce correspondence between the vendor and the licensee stating that the lesser torque was correct.
iii) The vendor manual specifies a certain material for the "0-ring" door gasket, whereas the licensee has installed new "0-ring" of different material.
The engineer stated that the old type
"0-ring" was replaced because
"better" material (extended life, environmentally qualified) became available.
The vendor manual is currently under the controls of the licensee's vendor manual verification program and therefore not available for unrestrictive use.
The engineer stated that these items would be considered during the verification process.
b.
- ~1 OHP 4030 STP.030,
"Operation Daily 8 Shift Surveillance Checks".
The inspector's observations on this lengthy procedure were limited to checkouts done on the Eberline RMS (radiation monitoring system)
channels.
c.
"*2 THP 4030 STP. 117,
"Steam Generator Mater Level Protection Set III".
The licensee keeps a log on his calibrated instrument test cart which traces instrument used against test performed.
If an instrument calibration problem occurs, the potentially affected tests can be identified.
The inspector noted the wrong "date performed" had been entered in this log for STP. 117; the mistake was immediately corrected.
d.
"*12 MHP SP. 126,
"Main Steam Safety Valve Set point Verification Using the Trevitest Equipment",
Revision 1 dated April 14, 1988.
e.
~~12 THP 4030 STP.211,
"Ice Condenser Surveillance".
No violations, deviations, unresolved or open items were identified.
7.
Fire Protection 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.
On April 11, 1988, the licensee telephoned a report to NRC Region III concerning planned maintenance on the outside fire protection ring header which rendered a part of'he fire water system inoperable.
Subsequently, and contrary to Technical Specification 3.7.9. 1 ACTION b.2b, the licensee failed (due to an administrative error) to provide the required written follow-up report the next working day.
The written report was provided on April 13, 1988, when the error was discovered.
The inspector reviewed this matter and found the licensee had identified and reported his own error, and the problem was neither safety significant nor repetitive.
In fact, at least a dozen instances of proper compliance to this reporting requirement were noted.
As such, pursuant to NRC Enforcement Policy as stated in 10 CFR Part 2, Appendix C, no Notice of Violation is being issued for this initial occurrence.
One violation (not cited)
and no deviations, unresolved or open items were identified.
8.
~Securit 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 March 18, 1988, a guard supervisor observed an officer who had Just reported for duty walking with an "unsteady gait".
After about two to three minutes of being observed, he was relieved of duty and administered a breath analyzer test onsite.
The initial screening test results read
. 075 (. 10 is legally impaired in Michigan).
While the individual was being transported to a local hospital for a blood test, he resigned.
No blood test was given, but the individual's site access was permanently revoked.
b.
On one facility tour, the inspector found an automatic monitoring device indicating a security door was not secure.
A touring guard happened by, and responded properly by verifying the door was secure and by reporting the monitoring failure.
A second guard responded promptly to take coverage of the door.
C.
At 1: 15 a.m.
(EDT) April 4, 1988, while conducting routine surveillance, an operations shift supervisor discovered two pieces of foam material inside the outboard bearing housing on the Unit 1 turbine driven auxiliary feedwater pump.
The nonflammable foam material is used as a fire barrier around pipe penetrations.
One piece was found lodged in the neck of the oil fill aperture, while the other piece was found floating on top of the oil in the bearing housing below.
The aperture, which is 1.5 inches in diameter, is covered by a spring operated cap.
The cap remains closed, so the foam material could not have found its way into the housing by accident.
Upon discovery, the shift supervisor issued a Condition Report and a
Job Order.
The foam material was removed by the end of the shift.
The licensee classified this item as equipment tampering and determined that this event was reportable per 10 CFR 73.71.
The appropriate notifications were made by 1:22 p.m.
on April 4, 1988.
The licensee's preliminary conclusion was that the foam material would not have caused the pump to fail if the pump were to start.
The licensee also checked the motor bearing housings on the other auxiliary feedwater pumps, but found no evidence of tampering.
Based on consultation with station management, a Confirmatory Action Letter (CAL-RIII-88-007) was issued on April 5, 1988.
The CAL had the following line items:
Brief plant operators and plant security personnel with regard to the event to provide a heightened state of awareness to the presence of foreign material in undesired places and/or in equipment.
.b.
C.
(Closed) Confirmatory Action Letter Item (315/88012-02; 316/88014-02).
The Operations and Security Departments included this as a line item in the shift. briefing for the oncoming crews.
Inspect each Auxiliary Feedwater (AFW) pump bearing for the presence of foreign material.
(Closed) Confirmatory Action Letter Item (315/88012-03; 316/88014-03).
The Maintenance" Department removed the end caps from all of the auxiliary feedwater pumps bearings and found no foreign material and no evidence of bearing damage.
Visually inspect accessible portions of other safety related motors/pumps for the presence of foreign material.
(Closed) Confirmatory Action Letter Item (315/88012-04; 316/88014-04).
The Operation's Superintendent instructed the Auxiliary Equipment Operation by night orders issued April 4, 1988, to conduct a close inspection of all fluid reservoirs.
This inspection included removal of caps to look inside.
No additional problems were found.
d.
Analyze the bearing oil in the Unit 1 turbine driven auxiliary feedwater pump outboard bearing for evidence of contaminants.
(Open) Confirmatory Action Letter Item (315/88012-05; 316/88014-05).
The bearing oil has been analyzed.
Preliminary evaluation indicated that the foam did not affect the lubricating properties of the oil.
This item will be closed when the results are submitted with e.
below.
Within 30 days, provide to Region III an update on the results of the above inspections and the analysis of the Unit 1 turbine driven auxiliary feedwater pump outboard bearing oil to be followed by a letter on these same subjects.
(Open) Confirmatory Action Letter Item (315/88012-06; 316/88014-06).
The report was not due at the close of this inspection.
However, the licensee understood that a Security Event Report (SER)
was required within 30 days of the initial
CFR 73.71 report.
The licensee plans to include the information requested by this CAL in the SER.
The inspector confirmed that this was acceptable.
f.
Should any further instances of potential tampering be found, immediately notify NRC RIII.
In addition, any evidence of tampering found during inspection should be preserved for NRC review.
(Closed) Confirmatory Action Letter Item (315/88012-07; 316/88014-07).
The Assistant Plant Manager - Administration, issued these instructions to the Security Department on April 5, and to the plant staff on April 6, 1988.
This item was clarified during a Region III/AEP conference call on April 5.
The clarification confirmed that preservation of evidence was not to hinder the licensee's ability to respond to events affecting plant safety or health and safety of plant personnel or the public.
No further evidence of tampering has been found.
During the investigation, bearing oil from another auxiliary feedwater pump was reported to be discolored.
Analysis showed that the discoloration was normal and not the result of tampering.
In addition, turbine driven auxiliary feedwater pump vibration tracing was performed and compared with results from previous testing; no degradation was observed.
Six Confirmatory Action Letter items were identified, of which four are closed.
No violations, deviations, unresolved or open items were identified.
9.
~Outa ee a ~
Unit 1 conducted a mid-cycle ice condenser surveillance outage on March 26-27, 1988 according to a preplanned schedule.
Ice basket weighing and upper containment test activities were performed with the Unit on line, finishing on March 24.
Radiological access considerations require Unit shutdown for lower ice condenser door tests.
with the Unit shut down, the lower containment, reactor coolant pumps and pump 'studs, and the reactor coolant piping system were inspected for the first time since October, 1987.
No leaks or boric acid accumulations were found.
b.
D.
C.
Cook, Unit 2, shut down as scheduled at 4: 30 a. m.
on April 23, 1988, for a major outage expected to last about nine months.
The inspector accompanied the initial containment inspection teams to inspect the lower containment and selected pumps, valves, piping and supports.
In general, good conditions were found, although some items needing maintenance were noted and recorded.
The Unit will be refueled; substantial testing will be performed; and numerous maintenance and modification jobs will be done.
The major project, however, will be the repair of the Unit's four steam generators, which have experienced chronic tube degradation, by
.replacement of the four lower assemblies (containing the tubes) with new assemblies.
This project, to be performed by M-K Ferguson under contract to and with direction by the licensee's corporate office, will take over from the operating group about June j., 1988.
NRC plans an integrated inspection of the various outage activities utilizing resident inspectors, specialist inspectors from NRC Region III, and an independent inspection of selected piping and welds using the nondestructive examination (NDE) van from the Region I office.
The licensee has held a number of briefings for and meetings with Region III (see Paragraph 13,
"Management Meeting" ) staff and management, with the Office of Nuclear Reactor Regulation (NRR) and with representatives of the State of'Michigan.
Unit 1 will continue normal operation and electrical production during the Unit 2 outage.
No violations, deviations, unresolved or open items were identified.
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 coordination 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, 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.
ll.
Re ortable Events 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.
(Open)
LER 50-315/86022,
"Personnel Error Results in Failure to Revise Rod Insertion Limit Following Technical Specification (TS)
Amendment":
this involved Unit 1 Amendment No. 74, effective September 30, 1983.
The problem was discovered in October, 1986.
This LER remains open pending reviews by Region III reactor physics specialists.
This LER is discussed in Paragraph ll.c below.
b.
(Closed)
LER 50-316/87003,
"Failure to Trip Overpower Delta Temperature Bistables During Power -Range Nuclear Instrumentation Calibration Due to Procedural Deficiency":
this involved Unit 2 Amendment No. 82, effective May 21, 1986.
The problem was discovered in January, 1987, and involved another failure to proceduralize a TS change.
This LER is discussed in Paragraph ll.c below.
C.
(Closed)
LER 50-316/88002,
"Surveillance Procedure Deficient Due to Cognitive Personnel Error When Reviewing Technical Specification Amendment for Impact on Procedures":
this again involved Unit 2 Amendment No. 82, and Unit 1 Amendment No. 99, issued at a different time.
This problem was discovered in February, 1988.
For items, a,
b and c above, the inspector determined reporting requirements were met and immediate corrective actions were appropriate.
The known procedure deficiencies have been corrected.
Item b and c are "closed" based on the following detailed evaluation concerning the latter:
i)
On February 5, 1988 the licensee determined through a review of
"Daily and Shift Surveillance" that Unit 2 channel checks for power range nuclear instrumentation were performed only in 17'
MODE 1 and 2.
The frequency of channel checks required by TS Table 4.3-1, is at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in MODES 1 and 2, and when the reactor trip system breakers are closed and the control rod drive system is capable of rod withdrawal.
The requirement for channel checks whenever the control rod system is capable of withdrawal was added to the Unit 2 Technical Specifications on May 21, 1986 as part of Amendment No. 82.
The reviewer failed to incorporate the amendment change into the procedures.
The licensee conducted a review of Unit 2 to identify times when channel checks were not performed at'the prescribed frequency.
The review identified two time periods (June
through June 29, 1986 and April 16 through April 20, 1987)
where checks were not performed as required.
The longest period of time the channel checks were not performed was thirty-five hours on June 28 - 29, 1986.
The repetitive LERs since October 1986, where an individual reviewing TS Amendments failed to adequately assess and incorporate additional requirements into procedures, show ineffective. corrective/preventive action to date.
In May 1985, the licensee assigned the review of TS Amendments to the Shift Technical Advisors group.
This change was to provide a more complete and coordinated review of such actions.
Although the reviews appear to be better coordinated, the single technical review has not ensured that all TS Amendments are incorporated into procedures.
Because the licensee's corrective actions for problems found in October 1986 and January 1987 did not identify the violation in June 1986 and the prevent a violation in April 1987, a Notice of Violation is being issued for these violations (Violation 316/88014-08).
One violation, and no deviations, unresolved or open items were identified.
12.
Enforcement Conference An enforcement conference, attended as indicated in Paragraph 1.b above, was held in the NRC Region III offices on March 17, 1988.
The purpose of the conference was to discuss a potential violation, with three examples, documented in Inspection Report 50-315/88003(DRS);
50-316/88004(DRS)
regarding the failure to implement adequate fuse-breaker coordination design control measures.
The licensee made a presentation on the fuse-breaker coordination studies as they relate to the 250 VDC safety busses and the Local Shutdown and Indication (LSI) panels.
They discussed the miscoordination issues, safety significance, and corrective actions to preclude further instances of inadequate design control involving fuse-breaker coordination.
NRC staff questions were adequately addressed during the presentation.
f At the conclusion of the conference, the Region III staff reviewed the information presented by the licensee.
The staff concluded the licensee was in violation; however, since neither of the two D.
C.
Cook Units had experienced a loss of electrical power to the above equipment, the three examples were categorized as one Severity Level IV violation.
The licensee was informed of this finding by letter dated March 30, 1988, which included a Notice of Violation.
Mana ement Meetin A management meeting, attended as indicated in Paragraph 1.c above, was held in the NRC Region III offices on April 6, 1988, to discuss the Unit 2 steam generator repair project.
The licensee discussed post changeout testing including return to service testing; modifications made to the radiological and security facilities; the differences between the installed and replacement generators; the quality control/assurance aspects of the replacement; and, auxiliary building crane modifications.
After the presentation a brief question and answer session was held.
Unresolved Items Unresolved Items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.
An Unresolved Item disclosed during the inspection is discussed in Paragraph 5, "Maintenance".
Confirmator Action Letter Items Confirmatory Action Letters (CAL) are letters confirming the licensee's agreement to take certain actions to remove certain concerns.
CALs are issued as soon as practical after identification of a significant condition that requires corrective action by the licensee.
CAL items identified during this inspection report are discussed in Paragraph 8,
"Security".
Mana ement Interview The inspectors met with licensee representatives (denoted in Paragraph 1)
on April 27, 1988, to discuss the scope and findings of the inspection.
In addition, the inspector asked those in attendance whether they considered any of the items discussed to contain information exempt from disclosure.
No items were identified.
The following items were specifically discussed:
a.
interpretations of Technical Specifications 3.0.3 and 3.0.5 (Paragraph 3);
b.
an Unresolved Item involving review of the licensee s Justification for Continued Operation (JCO) with certain valve motors equipped with an obsolete design torque switch (Paragraph 5);
a late licensee report involving fire protection equipment (Paragraph 7);
the status of Confirmation of Action Letter items concerning suspected tampering (Paragraph 8); and, a Violation resulting from failure to proceduralize a change to Technical Specifications (Paragraph ll).
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