IR 05000315/1987007
| ML17325A062 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 04/13/1987 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17325A061 | List: |
| References | |
| 50-315-87-07, 50-315-87-7, 50-316-87-07, 50-316-87-7, NUDOCS 8704280174 | |
| Download: ML17325A062 (36) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/87007(DRP);
50-316/87007(DRP)
e Docket Nos. 50-315; 50-316 Licenses No. DPR-58; DPR-74 Licensee:
American Electric Power Ser vice-Corporation Indiana and Michigan Electric Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, Michigan Inspection Conducted:
February 24 through March 31, 1987 Inspectors:
B. L. Jorgensen J.
K. Heller Approved By:
B. L. Burge Chief Projects S 'A d
~ L5 $?)7 ate Ins ection Summar Ins ection on Februar 24 throu h March 31, 1987 Re orts No. 50-315/87007 DRP
No. 50-316 87007 DRP Areas ns ecte
outine unannounced inspection by the resident inspectors o
actions on previously identified items; operational safety; reactor trips; radiological controls; maintenance; surveillance; fire protection; emergency preparedness; security; outages; training and qualification effectiveness; reportable events; allegations, and NRC Region III requests.
Results:
No violations or deviations were identified in any of the 14 areas inspected.
8 0428017'
R ADOQg pg000~
DETAILS 1.
Persons Contacted W. Smith, Jr., Plant Manager
- A. Blind, Assistant Plant Manager, Administration
- J. Rutkowski, Assistant Plant Manager, Production L. Gibson, Assistant Plant Manager, Technical Support
- P. Barrett, Acting Licensing Activity Coordinator
- T. Kriesel, Technical Superintendent, Physical Sciences
- K. Baker, Operations Superintendent
- E. Morse, guality Control Superintendent
- T. Beilman, 18C/Planning Superintendent
+J. Allard, Maintenance Superintendent T. Postlewait, Technical Superintendent, Engineering M. Horvath, (equality Assurance Supervisor R. Clendenning, Radiation Protection Supervisor
- R. Simms, Shift Technical Supervisor
- G. Caple, Administrative Compliance Coordinator, STA
- D. Krause, Administrative Compliance Coordinator, I8C
+R. Jones, Maintenance Supervisor
- J. Kauffman, I8M Construction Manager
- J. McElligott, AEPSC Site (juality Assurance The inspector also contacted a number of other licensee and contract employees and in ormally interviewed operations, maintenance, and technical personnel.
- Denotes some of the personnel attending Management Interview on April 1, 1987.
2.
Actions on Previousl Identified Items Region III Management has requested that the resident inspector review the Region III outstanding items list and address items that are greater than two years old.
For the items listed below, the inspector reviewed the licensee's documented actions.
For any item not involving identified regulatory requirements, the inspector administratively closed the item based on the licensee's actions.
If a violation or potential violation of regulatory requirements was identified the old item was closed and a new item established.
Concerning old open or unresolved items for which the licensee had taken no action, the item was either closed or replaced by a new item, depending on inspector judgement of the circumstances.
For Items 1, 2, and 3 below, Inspection Reports No. 50-315/83001; No. 50-316/83001 requested that the licensee respond to each unresolved item.
The licensee response (AEP:NRC:06250)
was dated July 15, 198 (1)
(Cl osed)
Unresolved Items (315/83001-10; 316/83001-10):
the licensee-initiated matrix to identify procedures which implement each of the requirements of ANSI N18.7-1976 was incomplete at the time of the inspection.
The licensee's response committed to complete the matrix using AEPSC plant gA personnel as time permitted.
l}uality Control Surveillance Report No. 85-0770 documents that the matrix was completed by the AEPSC site gA Department.
(2)
(Closed)
Unresolved Items (315/83001-12; 316/83001-12):
design change RFC-12-2528,
"Control Room Ventilation" did not receive complete design input considerations.
This was indicated by the necessity for an addendum to the RFC to add steps to verify completion of the change.
The licensee response stated that a
comprehensive review of all criteria required to institute, install and implement a design change was underway and that this finding would be evaluated.
guality Control Surveillance Report No.. 85-0770 documents that the review was performed and that no programatic changes were made as a result of this item.
(3)
(Closed)
Unresolved Item (315/83001-11; 316/83001-11):
several design change packages were inadequately controlled during installation such that operability requirements for redundant equipment were violated, and prior authorization/review wer not obtained.
The licensee response committed to comprehensive review of the design change program.
guality Control Surveillance Report No. 85-0770 states that Procedure PNI-5040,
"Design Changes" Revision 6, requires the development of design change guidelines.
The inspector reviewed PNI-5040 and verified the concern has been addressed.
b.
(Closed)
Open Items (315/84001-02; 316/84001-02):
improve licensee/
State communications concerning Protective Action Recommendations (PARs).
This matter was re-identified as an open item (315/86016-03; 316/86016-03)
when observations of an Emergency Plan exercise in July 1986 determined this to be an exercise
"weakness".
Subsequently, the issue was examined again and closed in Inspection Reports No. 50-315/86036(DRSS);
No. 50-316/86036(DRSS).
c ~
(Closed)
Unresolved Items (315/87004-02; 316/87004-02):
operators were not informed, by procedure changes or training, of a setpoint change.
The inspector was concerned that as an example, overspeed trip setpoints on the turbine driven auxiliary feedwater pumps (TDAFP), which were not given prior review and approval as design changes under
CFR 50.59, and information concerning them was not well disseminated, might indicate programmatic weaknesses in the handling of setpoint changes.
The inspector found that the TDAFP trip setpoint changes were initiated by an Engineering Control Procedure (ECP) dated July 17, 1985 and at that time, setpoint changes were not uniformly treated (especially in regards to 50.59
review) as design changes requiring review by the Plant Nuclear Safety Review Committee (PNSRC)
and followup dissemination of design change information.
Thus, the suspected programmatic weakness did exist.
Subsequently, in August 1985, the licensee revised the controlling
. administrative Procedure (PMI-5040, "Design Change Control Program",
Revision 6, Change Sheet No. 5) to specify setpoint changes were to be treated as Plant Modifications.
This designation continues to the present.
Plant Modifications are a class of design changes for which prior PNSRC review under 50.59 is mandatory.
Further, a
Design Change Coordinator is assigned whose duties include identification of procedures, drawings, prints, etc. which must be changed as a consequence.
Steps also exist to assure design change information is disseminated via training.
These actions were verified by examination of a few recent setpoint change type Plant Modifications.
They appear to have removed the programmatic weakness whichexisted prior to August 1985, with one possible exception.
Procedure PMI-5040 contains a list of definitions in its Appendix C.
The definition for "Plant Modification" specifically excludes changes to the "Relay Setpoint Setting Document" from coverage under the design change process.
The inspector had further discussions with licensee personnel concerning the nature and content of the "Relay Setpoint Settirg Document" and learned that this is a controlled document which specifies setpoints for electrical equipment protective relays such as instantaneous and time overcurrent devices, motor overtemperature relays, and generator differential current relays.
A brief review established numerous relay setpoint adjustments h'ave been made over the years, including adjustments to relays for protection of safety-related pumps and the emergency diesel generators.
These matters are under the control of the licensee's corporate technical organization, rather than plant Procedure PMI-5040.
Further review is needed to ascertain whether appropriate technical and safety reviews are implemented in controlling electrical protective relay setpoint settings.
A new Unresolved Item will focus on this narrower remaining issue, (Unresolved Items 315/87007-01; 316/87007-01).
(Open)
Open Items (315/85036-01; 316/85036-01):
procedure changes made for one Unit need to be reviewed and implemented for the other Unit, if applicable.
The Operations Department has developed a
Procedure Change Sheet (PCS)
review checklist which specifically includes consideration of the need to apply a contemplated change across associated procedures for both Units.
The remaining Departments rarely segregate procedures by Unit, except for the Instrument and Control group, which has a procedure,
"Writers Guide",
in preparation which is expected to address this issue in its coverage of procedure change e.
(Cl osed)
Open Items (315/86041-02; 316/86041-01):
preferred position of RHR mini-flow valve.
The licensee reviewed the position of the residual heat removal pumps'ini-flow valves and determined that
"Closed" was the preferred position when the pump is in standby.
Because the system configuration involves a crosstie between pumps, keeping the valve closed prevents short-circuiting pump flow via the opposite mini-flow valve if the opposite pump fails to start.
This was considered in the system design basis.
One Unresolved Item and no violations, deviations, 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 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 at its 90% power target essentially throughout the inspection period, with two brief power reductions to perform testing and maintenance on the 1E main feed pump.
b.
Unit 2 operated at 80% power as targeted until development of a primary. to secondary leak in the No.
22 steam generator forced commencement of a maintenance and testing outage on March 3, 1987.
Outage activities are discussed in Paragraph ll.
The inspector specifically included observation of Unit shutdown activities from the Unit 2 main control room on two separate tours on March 3.
On the first occasion, the licensee was ramping down via boration through 35 percent power and decreasing.
A smooth, on-target rate was being maintained as shown by temperature and nuclear power traces.
The second observation period covered taking the main electrical generator off-line, starting up auxiliary
feedwater and securing main feedwater, and commencing rod insertion.
Communications and co-ordination at all three stations were problem-free and clear, despite about 30 feet of physical separation due to the large layout siz'e of the D.
C.
Cook control rooms.
The inspector reviewed selected Operations Department procedures from both a technical and an administrative perspective, as follows:
2-OHP 4021.017.001
"Operation of the Residual Heat Removal (RHR) System",
Revision 0 dated September 18, 1986.
This procedure describes necessary actions for removing one RHR pump from service when both are operating, and for transfer ring from operation of one pump to operation of the other.
No specific instructions are provided concerning valve and flowpath lineups.
Rather, generic guidance provides for establishing letdown and cooldown lineups as needed considering equipment availability.
The RHR system in Unit 2 was in service under this procedure for much of the inspection period, and was in an unusual alignment because an extensive inspection project on,the component cooling water system affected RHR system component availability.
The licensee prepared a series of controlled piping drawings to establish and maintain the desired configurations and to enable rapid, confusion-free RHR pump transfer if needed.
(2)
(3)
(4)
2-OHP 4021.017.002
"Placing in Service the Residual Heat Removal System",
Revision 5 dated September 18, 1986.
- 2-OHP 4021.017.003
"Removing Residual Heat Removal Loop From Service", Revision 2 through Change Sheet 1 dated June 26, 1986.
2-OHP 4024.206
"Annunciator No.
6 Response
- Residual Heat Removal", Revision 1 through Change Sheet 3 dated January 15, 1984.
No setpoints were provided for the safety injection and RHR pump motor "Instant Trip" and motor "Overload Trip" alarms (Drops 010, 015, 045, and 050), consistent with the licensee's segregation of these type electrical protection trip devices and setpoints as discussed in Paragraph 2.c.
An erroneous
"Probable Cause" statement for Drop 048 "(IMO-128)
RMR OPEN TO HI RCS PRESSURE" indicated 'this was a "normal alarm during normal operation".
Design Change RFC-DC-12-2645 eliminated this nuisance alarm by suppressing it if isolation Valve INO-128 is fully closed, as is usually the case.
Other aspects of the design change were reflected correctly.
The Unit 2 control room operator immediately initiated a correction request.
The Unit 1 procedure did not contain the same erro Followup review of the same procedure using the Operations Department office controlled copy found Change Sheet 3 posted at the front of the procedure, but no new page for Drop 048.
This was immediately corrected.
(5)
1-OKP 4024. 115 "Annunciator No.
15 Response
- Feed Pump Turbine", Revision 4 through Change Sheet 3 dated September 17, 1985.
The licensee had performed several evolutions, including derating Unit 1, to investigate an intermittent 1E main feedpump high vibration alarm.
While discussing the alarm condition on one occasion, the inspector and a control room operator referred to the above procedure.
They found the stated setpoint for high vibration (Drop 042 - five mils) had been supplemented with a red ink notation,
"2 mils".
This notation created some doubt as to what was the genuine setpoint was.
The operator showed a clear awareness that controlled procedures are not to be revised by ink markings, nor are they to be used for making any kind of notations.
The annotated page was immediately replaced with a "clean" page from another controlled procedure copy, and a verification check found five mils is correct for this setpoint.
Because this has become a standing alarm with other indications showing actual vibration to be well below five mils, it is believed the setpoint on this instrument has "drifted" to about two mils.
The notation may have reflected that speculation.
d.
During one tour in the auxiliary feedwater pump rooms on March 2, 1987 the inspector noted an "overdue" calibration sticker on instrument 1-CLI-110 which is the condensate storage tank level instrument located in the Unit ) turbine-driven auxiliary feedwater pump room.
It would be an important reference instrument for plant
"safe shutdown" from outside the main control room.
The calibration sticker affixed to the instrument indicated that the last calibration date was August 1984, with a "next due" date of February 1986.
The analogous Unit 2 instrument,(2-CLI-110)
was within the frequency indicated on its sticker.
Further review established that the subject instrument was not among those for which mandatory calibration frequencies had been established by Technical Specifications or procedures, nor was it 'entered on the licensee's computerized scheduling system.
The Unit 2 instrument, however, was on the scheduling system, and licensee representatives subsequently added the Unit 1 instrument to the schedule and initiated a Job Order for a new calibration immediately upon being advised of the problem.
The inspector specifically noted the instrument in question agreed with the main control room indication, which is currently calibrated.
The new calibration was completed March 5, 1987.
General controls for "local" instrument calibrations are
'iscussed further in Paragraph 7 "Surveillance".
e.
\\
I The inspector performed a walkdown/review of the Unit 1 Residual Heat Removal System using licensee Procedure
- l-OHP-4021.008.002 Valve Lineup Sheet No.
7 to verify that:
each accessible flow path valve was in its correct position; power (visual breakers and fuses)
was aligned to activate on automatic signal; essential instrumentation was operable, and; no condition existed that degraded the system.
No violations, deviations, unresolved or open items were identified.
4.
Reactor Tri Si nal A reactor protection system (RPS) actuation occurred in Unit 2 at 3:11 p.m.
on March 3, 1987.
The Unit was subcritical at the time, and plant operators were inserting shutdown bank control rods per procedure so the Uni.t could initiate a maintenance and testing outage.
Nuclear instruments N-31 and N-32, the source-range instruments, had re-energized as designed.
The RPS actuation was then caused by an upscale
"spike" on instrument N-31, which initiated a source range high flux trip.
All rods which were still withdrawn tripped as designed, and the response of the Unit was nominal in all respects except for the initiating instrument (N-31), which "hung up" at around 100,000 cpm.
Subsequent to the trip, the inspector reviewed the plant response and the status of the reactor ard safety systems by observation nf control room indicators and by discussions with licensee personnel concerning plant parameters and safety system status.
No additional items were identified.
Telephone notifications for this event were made as required per
CFR 50.72.
Further evaluation is anticipated in review of the expected Licensee Event Report on the matter.
Outage activities.are discussed in Paragraph 11 below.
No violations, deviations, unresolved or open items were identified.
5.
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 ~
Among the items verified during auxiliary building tours was an appropriate change in the frequency of surveying selected areas as a consequence of the Unit 2 shutdown.
Licensee Procedure
THP 6010 RAD.200, "Routine Radiation and Contamination Surveys",
changes the frequency for surveying the RHR pump rooms and heat exchanger rooms from monthly to weekly.
The licensee prop'er ly implemented these requirements; however, in the case of the RHR
heat exchanger rooms copies of'he survey performed on March
were not posted locally at the room entrance.
When this was discovered by the inspector a week later, another survey had been done which was then posted to reflect the more current conditions.
b.
On March 16, 1987 the inspector performed independent radiological surveys on a Model HN 200 shipping cask loaded with spent resin.
This cask had been prepared for shipment to a licensed low-level waste burial site.
Licensee technicians were performing surveys and obtaining contamination smears concurrently with the inspector's checks, and their techniques were observed and results checked against those obtained by the inspector.
Direct radiation readings by both parties were closely comparable and well below regulatory limits. 'he documentation being developed to accompany the shipment was also briefly examined, with no adverse observations.
c.
During tours of the auxiliary building the inspector found and discussed the following items with the Radiation Protection Manager (RPM).
(1)
Two portable blast cleaning machines (Serial Numbers G5-2 and G5-1), stored in the hot tool crib area, had the following written on duct tape affixed to the top of each machine:
"In future make sure -.+he hose connection is taped closed.
This is an airborne hazard."
The inspector notes that if an airborne problem exists when the machines are in use, then a more permanent warning is advisable.
The RPM acknowledged the inspectors comments and agreed to review this item.
(2)
The biweekly radiation survey sheets dated March 16, 1987 for the spray additive tank rooms did not show a contamination boundary which existed in the room.
This was discussed with the onshift Radiation Protection Supervisor who explained that the boundary had been changed to facilitate future work.
The supervisor acknowledged that the status sheet had not been changed, indicating there was no requirement to change the posted status sheet to reflect the new boundary.
The inspector discussed this with the RPM and was informed that the status sheets are not identified in the plant radiation protection procedures.
However, a revision to RAD-200 was underway to address the status sheets.
(3)
The local posting area for the radiological survey status sheets on the Unit 1 charging pump rooms had space to display only one survey sheet, however three sheets are used for this area.
This was discussed with the RPM who agreed to expand the posting area.
During subsequent tours the inspector found that all three survey sheets were displayed.
d.
During this inspection period the licensee informed the inspector that the Radiation Protection Manager has submitted his resignation
effective April 16, 1987.
This information was provided to the NRC Region II: office. As of'he close of the inspection the licensee had not formalized plans for a replacement.
No violations, deviations, unresolved or open items were identified.
6.
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 705288 Observed cadwelding of ground cable for new Unit,2 battery 2CD room ventilation unit, in support of design change RFC-DC-2788.
Verified correct, current "Welding, Burning, Grinding Permit" No. 87/107.
b.
Job Order 015823 Review repairs of Steam Generator No.
secondary side manway cover.
c.
Job Order 707577 Observed repairs to heater drain pump.
d.
. During an auxiliary building tour on March 24, 1987, the inspector found a Job Order tag hung on the access ladder to the main steamline overhead walkway which concerned a steam leak on Unit 2 valve 2-MS-148 and which was dated October 25, 1985.
This was pursued with the Maintenance Department because the licensee had ample opportunity during the 1986 Unit refueling to perform this repair.
The licensee review found that the repair had been performed'in 1986 but that not all the associated tags had been collected as intended.
The subject tag was removed.
e.
The Maintenance Department was advised when the inspector found a
Unit 1 main feedwater constant support (Serial No. 1-GFW-C-231)
which appeared to be off its adjustment target.
The licensee determined the support was about an inch off its "hot setting" target, but it was not bound and the tamper seal installed on the
~ ~
adjustment nut was intact.
A work request was written to investigate further during the Summer 1987 refueling outage.
The subject support is outside containment, outboard of the isolation valves.
No violations, deviations, unresolved or open items were identified.
7.
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 proper ly reviewed and resolved by appropriate management personnel.
The following activities were inspected:
a.
Observed (1)
- 1 THP 6030 IMP.067 "Core Exit Temperature Monitoring system Calibration".
(2)
- 2 THP 4030 STP.034, Data Sheet 3,
"RHR Cooldown Suction Valves".
(3)
- 12 THP 4030 STP.211 "Ice Condenser Surveillance";
see also Paragraph 14, "Allegation", and Paragraph 12, "Training".
(4)
"*12 THP 4030 STP.207 "Ice Condenser Lower Inlet Doors Opening Force";
see also Paragraph 12, "Training".
b.
Reviewed (1)
- 1 OHP 4030 STP.008
"Emergency Core Cooling System Cold Shutdown Test".
(2)
- 1 OHP 4030 STP.050E
"East Residual Heat Removal Train Operability Test - Modes 1-4", Rev.
1 through Change Sheet
dated 2/12/87.
(3)
- 1 OHP 4030 STP.050W
"West Residual Heat Removal Train Operability Test - Modes 1-4", Rev.
1 through Change Sheet
dated 10/16/86.
The inspector found Change Sheet 2 for the East train added three "precaution" statements relating to administrative controls on the amount and duration of permissible
recirculation flow to the RWST.
These statements are fully applicable to the West train procedure as well, but no Change Sheet had been posted for that procedure.
Similarly, the analogous Unit 2 procedures lacked the new precaution statements.
A check with the Operations procedure section established they were aware of the disparities and had already forwarded a Change-Sheet relating to Unit 1 West train for approval by the Subcommittee on Procedures.
The Unit 2 Change Sheets were being prepared.
This matter bears on an Open Item relating to inter-Unit procedure conformity discussed in Paragraph 2.d above.
(4)
OHP 4030 STP.054E
"East Residual Heat Removal Train Operability Test - Shutdown",
Rev.
0 through Change Sheet
dated 7/ll/86.
(5)
OHP 4030 STP.054M
"West Residual Heat Removal Train Operability Test - Shutdown",
Rev.
0 through Change Sheet
dated 7/17/86.
Items 4 and 5 above contained minor differences as a
consequence of four Change Sheets being processed in one case and six in the other.
c.
Problem Investi ation (1)
- 2 OHP 4030 STP.013A
"No.
2 (Train "A") Electric Hydrogen Recombiner Semi-annual Functional Test", performed 6/24/86, 6/26/86, ano 10/30/86.
(2)
- 2 OHP 4030 STP.013B
"No.
1 (Train "B") Electric Hydrogen Recombiner Semi-annual Functional Test", performed 1/30/86 and 7/30/86.
(3)
- 12 THP 4030 STP.206 "Surveillance Test Procedure:
Electric Hydrogen Recombiner",
performed 9/9/85 (Train "B"), and 10/22/85 (Train "A").
These procedures were reviewed to determine if they contributed to condition report 2-3-87-0442 and problem report 87-217 which identified that one of five heaters to Unit 2 Hydrogen Recombiner No.
2 was wired improperly.
The inspector was not able to determine if any of the procedures contributed to the problem.
The inspector did find that STP.206 involves the lifting df heater leads and that the current revision requires verification that the leads are landed properly.
In addition, the inspector found that the data recorded in 1985 for STP.206 (Trains "A" vs. Train "B") was not consistent, apparently due to imprecise data recording instructions.
The
inspector suggested the procedure be reviewed for possible clarification.
The licensee believes the miswiring may have occurred prior to current strict procedure controls being developed.
The recombiner is apparently capable of passing surveillance criteria even with the miswired heater.
d.
Miscellaneous As noted in Paragraph 3.d above, the inspector observed an "overdue" calibration sticker on instrument 1-CLI-110, the Unit I condensate storage tank level instrument located at the turbine driven auxiliary feedwater pump room.
A subsequent general survey of numerous other local instruments located throughout various systems identified several additional instruments which had "overdue" calibration stickers affixed.
These included instruments CPA-410 and CPS-410 ("due" 2/7/87),
CPA-420 and CPS-420 (I/25/87), and CPA-430 and CPS-430 (I/24/87).
These instruments provide discharge low pressure alarm and actuation signals relating to component cooling water pumps lE, 1M and "spare", respectively.
Further discussions were then held concerning these instruments in particular and the use of "field" calibration stickers in general.
Concerning these instruments, licensee Instrument and Control personnel (ISC) determined a 5-year frequency had been established for the CPS instruments, on the official Instrument Calibration Schedule (ICS), not the 18-month frequency suggested by the sticker.
The CPA instruments have no specified ICS frequency, but are calibrated each replacement or repair.
Licensee representatives stated the ICS is the schedule controlling mechanism, and that in the future, field calibration stickers will be neither used nor regarded.
No violations, deviations, unresolved or open items were identified.
8.
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.
a ~
During a tour of the auxiliary building on March 3, 1987 the inspector found a scaffold erected across the East end of the central hallway at the 573-foot elevation, just outside the 1E containment spray pump room, which reduced accessibility of two fire extinguishers mounted on the end wall.
The licensee's scaffold control program involves a "permit" system with reviews and special instructions as found applicable.
The permit tag in this case included standard instructions to the effect:
"do not block access
to fire protection equipment."
The licensee re-examined this situation at the inspector's request and determined it was acceptable considering the brief time for which the scaffold was authorized and -the ready accessibility of other extinguishers and hose reels in the area.
b.
A small fire occurred in the Unit 2 containment annulus on March 12, 1987 when sparks from a welding repair in the overhead ignited a single rag on the floor.
The firewatch assigned to the welding job immediately extinguished the fire with no need for assistance from the onsite fire brigade.
The inspector verified proper reporting, documentation and evaluation per procedure PMI-2270 "Fire Protection."
c.
The inspector verified compliance to requirements for control of
"hot work" via a welding, burning and grinding "permit" system, when observing maintenance or construction involving such.
d.
On March 17, 1987 a portion of the plant yard ring header was isolated to permit repair of a headel leak.
Associated reporting requirements were complied with.
No violations, deviations, unresolved or open items were identified.
9.
Emer enc Pre aredness The inspector routinely toured the Technical Support Center (TSC)
and on one occasion accompanied a licensee representative to the Emergency Operations Facility (EOF) while the licensee was testing the emergency phone systems.
During these tours, the inspector did not find any conditions which would have prevented the facilities from functioning as designed.
No violations, deviations, unresolved or open items were identified.
10.
~Secur it 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.
During this inspection period, the licensee's
"fitness for duty" program identified one employee via bioassay with a positive THC result.
This is the first licensee employee so identified as having an indication of proscribed drug involvement.
The individual's site access authorization was suspended pending either rehabilitation and/or discharge or reassignment to another, non-nuclear site.
The resident inspector and the NRC Region III office were notified by the licensee (as a courtesy)
the morning after the positive result was verified.
b.
The licensee notified the resident inspectors and the Region III office that 12 contractor employees had tested positive for THC during an unannounced drug screening test was conducted on March 18, 1987.
The 12 contractor employees'ite access has been revoked.
For items a.
and b., Region III Safeguards specialists will monitor the licensee's activities during the next scheduled inspection.
c.
The licensee uses trained dogs in the program for detecting and dissuading any attempts to bring banned materials on or around the site.
The inspector observed the utilization of one of the dogs in workplace screening during the current inspection.
d.
Implementation of a design change to ensure more reliable automatic closure of the main control room entry doors was briefly examined.
A committed completion date of April 1, 1987 was met.
No violations, deviations, unresolved or open items were identified.
11.
~0ata ea Unit 2 commenced a maintenance and testing outage on March 3, 1987.
An outage schedule had been prepared for implementation beginning in mid-April, 1987, which was adjusted and implemented early'when development of steam generator tube leakage forced the Unit shutdown.
a ~
The inspector routinely attended outage planning and management meetings to maintain current status on progress against the schedule and to observe decision-making on new information developed as a
consequence of various maintenance or test activities.
Higher level management was aggressively involved in daily outage reviews and decisionmaking.
b.
Major activities performed during the outage included:
i c ~
d.
(i)
100 percent eddy-current testing (ECT) of all four steam generators t
(ii)
plugging of tubes identified by 'ECT or leakage indication (iii) reactor coolant pump seal ring replacement for all four RCPs (iv)
nondestructive examination of over 400 component cooling water system welds (v)
ice condenser surveillance (vi)
repair of steam generator manway bolt-holes (vii)
several hundred Job Orders for repairs.capable of completion only with the Unit shut down (viii}numerous design changes requiring shut down conditions (iv)
finding and repairing a reactor vessel support cooler leak.
Only items iii', v, vii, and viii were of known scope or existence at the beginning of the outage.
Incorporation of the evolving work relating to the rest of the items was considered both prudently and efficiently done.
Nuclear Instrument N-31, which failed at the outset of the outage as noted in Paragraph 4 above, was tested, determined faulty, and replaced.
The leaking steam generator tube in Steam Generator No.
22 which precipitated the early outage was identified visually by secondary system pressurization causing leakage at the tube sheet.
Leakage was apparently confined to one tube.
The inspector kept NRC Region III technical specialists informed concerning eddy-current findings, which ultimately led to plugging of several dozen tubes.
No violations, deviations, unresolved or open items were identified.
12.
Trainin and gualification Effectiveness For each area addressed in this report, which involved inspector observation of'he conduct of activities and/or discussions with licensee personnel, the inspector's evaluation included a judgement of the degree of knowledge or skill exhibited.
a ~
The inspector interviewed the personnel performing
- 12 THP 4030 STP.211 "Ice Condenser Surveillance" and
- 12 THP 4030 STP.207 "Ice Condenser Lower Inlet Door Opening Force" and found that they were able to repeat the sequence of steps and explain why the test was performed, from memor b.
The inspector met on February 26, 1987 with a representative of the Training Department to discuss processes for evaluation'of the effectiveness of training activities.
A meeting with senior management responsible for training functions is tentatively scheduled for early April, 1987.
c.
Reviews were performed on the following procedures involving policies, administrative controls and implementation practices in the training area:
i)
PYiI-2070 "Training", Revision 8 dated 7/26/85 ii)
12 PNP-2070-TRN-003
"Evaluation of Training Program Effectiveness",
Revision 0 dated 7/10/85.
This procedure was developed for implementation as new training programs, oriented to INPO accreditation, were developed and approved, with a final implementation date for all approved programs of January 1, 1987.
It establishes quite detailed meet anisms for both objective and subjective feedback to the training organization, from trainees and their supervision/management, concerning strengths and weaknesses (usually emphasizing the latter) of each course.
d.
A discussion was,held with a representative of the Training Department concerning mechanisms for receiving, reviewing, and incorporating appropriate information from NRC documents into licensee trainino programs.
The documents under discussion were I.E. Bulletins, I.E. Information Notices, and Generic Letters, all of which are intended to inform licensees of potential concerns or events relating to the nuclear industry.
No violations, deviations, unresolved or open items were identified.
13.
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 ~
(Closed)
LER 50-315/85048, Revisions 0, 1, 2 and 3:
an incorrect replacement part was installed on the turbine-driven auxiliary feedwater pump due to inadequate programmatic controls for replacement parts.
The normally energized trip and throttle valve latching solenoid was subject, due to strenuous service conditions involving continuous holding of an approximate 30-pound weight, to several failures over plant life.
Lack of 'stringent controls to original design requirements permitted selection and installation,
beginning in about 1976, of a non-qualified solenoid (GE yodel No.
950320BAG2) in lieu of the qualified model (GE Model No. 950320BAF2).
The incorrect model was replaced "in kind" for repairs subsequent to 1976.
On discovery of 'this problem, the licensee installed a correct solenoid, removed all non-certified solenoids from inventory, mounted permanent tags on the pumps identifying the correct parts, and emphasized requirements and sources for correct parts verification in personnel training.
A study was subsequently conducted to compare solenoids which concluded the non-certified parts would not reasonably be expected to degrade availability of the pump.'his functional equivalence, taken together with frequent independent tests and visual checks, and considering the fu'nction of the solenoid involved re-latching after pump trip, not standby readiness, leads to the conclusion the problem did not have major safety significance.
(Closed)
LEP, 50-315/86002, Revisions 0 and 1:
Reactor Protection System (RPS) setpoints were not in literal compliance with Technical Specifications due to mis-interpretation of requirements during original development of plant procedures.
Interlocks P-6, P-10 and P-7 (through P-13)
had historically been set very near, but on the incorrect side (e.g. just above vs. just below, or vice versa) of specified points because
"greater than" or "less than" symbols in Technical Specifications iere taken to mean where to establish the setpoint rather than where to provide assurance the setpoint ad been reached.
Thus, as one example, assuring an -interlock had been reached for power levels "below 9 percent" requires a setpoint just above 9 percent, not one just below.
The identified procedural deficiencies were corrected.
(Closed)
LER 50-315/06005, Revision 0:
a tempered glass test specimen of the type used in the containment airlock window failed when exposed to extreme high-level beta radiation.
The licensee learned of the failure in review of vendor information for airlock door seal material and, being uncertain whether the test conditions could apply at D. C.
Cook plant, designed and installed a 3/8-inch thick steel cover plate for the subject windows.
A report under
CFR Part 21 was incorporated with this LER, which is also considered closed for D.
C. Cook.
(Closed)
LER 50-315/86013, Revision 0:
failure to literally comply with Technical Specifications on loss of 4 KY bus voltage testing due to procedural deficiencies.
One deficiency involved the lack of a specific verification that the feedwater conservation signal is actuated on loss of 4 KV bus voltage.
A second deficiency involved the time response testing for auxiliary feedwater initiation.
Since there are three undervoltage relays, the licensee determined all possible ~airs of relays (two of three logic initiates the action)
would have to be tested to account for the slowest and to assure
none of the three were failed.
This had not previously been done.
The circuits were immediately tested satisfactorily, and the controlling procedures were revised.
(Closed)
LER 50-315/86014, Revision 0:
failure to verify Residual Heat Removal (RHR) system interlock action due to procedural deficiency.
During a procedure re-organization process in 1985, requirements for the subject demonstration were dropped.
Thereafter, because the procedures no longer specified the testin9, it was not performed at the previously required frequency of 18-months.
When the deficiency was discovered and the testing successfully performed, intervals of 32-months for Unit 1 and 30-months for Unit 2 had elapsed.
The procedural deficiencies were corrected.
(Closed)
LER 50-315/86019, Revision 0:
improper check of waste gas hydrogen analyzer calibration due to procedure violation.
After a gas analyzer calibration on July 3, 1986 a calibration check at 1 percent scale was performed with a hydrogen and argon mixture instead of a hydrogen and nitrogen mixture.
The check was repeated with satisfactory results using the correct mixture, establishing
'he analyzer would have performed as designed.
Appropriate administrative action was implemented for the involved individuals, who were aware of the procedure-specifiad mixture but used another they considered equivalent.
(Closed)
LER 50-315/86020, Revision 0:
main steam safety valves were found out-of-specification due to setpoint drift.
Eight of 20 Unit 1 main steam safety valves were found during surveillance testing in November, 1985 to be out-of-specification for liftsetpoints.
The surveillance procedure in use at the time is also a repair procedure which provided for immediate adjustment and -neglected to address considerations on reportability.
This led to the failure to issue an LER at the time (a Notice of Violation with I.E. Inspection Reports No. 50-315/86030(DRP);
No. 50-316/86030(DRP)
addressed the failure to report) which is now covered by the subject LER.
Any further coverage of this matter will be in followup to the Notice of Violation.
(Closed)
LER 50-315/86023, Revision 0:
a Unit 1 turbine trip and reactor trip resulted from an erroneous signal from the main turbine thrust bearing wear detector.
Some attributes of this event are discussed in I.E. Inspection Report No. 50-315/86041(DRP).
That report did not clearly state the fact that, following the trip, when one electronic monitoring system failed to show opening of the "8" trip breaker, the licensee immediately verified it was open.
The signal resulted from setpoint drift in the monitoring circuit, which was corrected.
Further, the adjustment procedure was changed to assure future drift, if any, is detected and corrected before turbine operation is jeopardized.
(Closed)
LER 50-315/86024, Revision 0:
engineered safety features ventilation fans were inoperable due to damper misalignment.
Following work on one ventilation train, during which time the train was inoperative and its fan suction damper closed, the other train was removed from service for similar work.
The first train, however, was no yet restored to operability because the fan suction damper remained closed.
The operator who was assigned to restore the first train found the suction damper appearing, by the indicator mounted on the manual positioning handle, to be already open.
The indicator bracket was incorrectly mounted, however, and showed the reverse of true damper position.
The discrepancy was discovered within a few minutes because of unusual fan noise, and it was corrected within the 1-hour time constraints of Technical Specification 3.0.3.
A subsequent survey of all manual damper positioners in both Units identified several more discrepancies involving indicator brackets, primarily in Unit 1.
No other dampers were found mispositioned as a consequence.
The discrepant conditions were immediately tagged when found and work requests were written for correction.
The licensee's investigation also disclosed some personnel performance discrepancies, as follows:
an operator
"
who originally closed the mis-mar ked damper and tagged it for the work activity recognized the local indicator was backward and discussed this fact with his supervisor, but neither individual initiated any corrective action, and; the operator why collected the tags believed the damper was open when the tag specified it to be closed, an error in the tagging/clearance program with reporting and corrective action requirements the operator did not then follow.
Appropriate administrative actions were taken for the individuals involved.
(Closed)
LER 50-316/85019, Revision 0:
the licensee determined in August, 1985 that the seismic qualification of the governors for the turbine driven auxiliary feed pumps had been historically indeterminate until May, 1985.
The governor manufacturer (Woodward Governor Co.) notified the turbine manufacturer (Terry Corp.) in 1981 that seismic analysis documentation for the governors was unavailable.
The turbine manufacturer then conducted a seismic qualification program themselves, finding the governors acceptable, as installed.
The licensee was unaware of the documentation discrepancy until being informed in 1985 it had been resolved.
The subject LER also constitutes
.the licensee's determination this event is reportable under
CFR Part 21, which issue is also considered closed for D.
C. Cook.
(Closed)
LER 50-316/86001, Revision 0:
the Unit 2 vent unit sampling for tritium was interrupted for about three weeks due to sample line freezing.
The Technical Specifications call for "continuous" sampling, with no guidance or time limits for conditions when sampling is interrupted.
The licensee cleared the sampling line of ice, repaired the failed heat tracing which allowed the freezing, and analysed the partial sample collected before the line froze.
No detectable tritium activity was found in the partial sample, nor in samples just before and just after the interruption period.
'c
(Closed)
LER 50-316/86012, Revisions 0 and 1:
routine Unit 2 surveillance testino disclosed ECCS flow imbalances caused by system degradation (first instance)
and improperly installed throttle valve locking devices (second instance).
The March, 1986 testing disclosed the safety injection flow balances failed specification in that total flow in Loops 2 and 3 from the South SI pump was too low (266.7 gpm vs.
300 gpm required) while four-loop flow off both pumps was too high (655 gpm vs.
640 maximum).
The boron injection flow balance was also excessive in total flow (515 gpm vs.
470 maximum)
and the differential between the high and low loop flows, at 20.4 gpm, exceeded the specified maximum differential of 10 gpm.
The system throttle values were readjusted so flow values in specification were achieved, and analyses were performed demonstrating the as-found imbalances threatened neither postulated peak cladding temperature limits nor pump operability.
Subsequently, in May 1986 the licensee discovered the throttle valve locking devices were not correctly installed.
Satisfactory retesting was performed on the safety injection system and the locking devices properly secured.
The boron injection system again exhibited an excessive maximum differential flow, and, for the firs" time, an inadequate total flow via the three lowest-flow loops.
This was found to be due to degradation of the Mest centrifugal charging pump rotating element, which was replaced.
Final testing and proper installation of the locking devices preceded Unit startup from the outage during which this entire evolution occurred.
As preventive action, procedure instructions were explicitly developed including a drawing, to assure cor rect locking device installation in the future.
(Closed)
LER 50-316/86014, Revision 0:
routine surveillance testing disclosed airflow in the ESF ventilation system slightly, above the specified maximum; 27,765 cfm vs. 27,500 cfm.
Filter efficiencies were within specification, showing filter bypass flow was not the cause.
The licensee concluded the procedures needed upgrading to allow for accounting of ambient temperature and pressure conditions, which would maximize accuracy in setting damper positions for the middle of the 22,500 to 27,500 cfm specified range.
The revisions were made, the testing was repeated and damper positions were established as determined by results.
(Closed)
LER 50-316/86018, Revision 0:
Technical Specification requirements for a radioactive effluent monitor channel check each 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, when discharging via the steam generator blowdown system, were not incorporated in channel check procedures for cold shutdown, during which time the blowdown system may be used to drain the steam generators.
Apparently, draining the generators when shut down was not explicitly recognized as a'ischarge dut ing original procedure development.
The procedures were revised to cover the omission.
procedures have always verified instrument operability before commencement of generator draining.
o.
(Closed)
LER 50-316/86029, Revisions 0 and 1:
degraded voltage relay calibration checks were not performed in the required interval.
Six Unit 2 relay calibrations were discovered, in October 1986 to be eight months delinquent.
The associated safety-related
KV buses were declared inoperable and a Unit shutdown commenced per Technical Specifications while calibrations were performed.
Satisfactory results were obtained on all six channels within 40 minutes.
Adjustments were required on three relays to increase their settings to within the required range.
The "Degraded Grid Voltage" study and subsequent analyses were referenced in the licensee's evaluation, which concluded the "as-found" conditions would not have had an impact on plant safety.
Evaluation of the computerized scheduling system, which disclosed the above items on the "overdue" listing for the first time at eight months overdue, did not establish precisely how the items were overlooked, nor why they then showed up after an extended period.
Historical records of i'nteractions on the computerized system were not retained during the period in question.
This has been changed, and increased training and administrative control checks have been implemented for scheduling system users.
',p.
(Closed)
LER 50-316/86030, Revision 0:
due to personnel error, a
containment isolation boundary valve was returned to service following maintenance without requisite testing being performed.
A technician performing a local leakrate test on November 11, 1986 detected leakage at the stem packing on one waste gas system valve, and tightened the packing nut.
Realizing then that this was not per procedure, he restored the packing nut to its approximate original position, but informed no one until the following day.
A valve stroke test was then successfully performed by the Chemistry Section on November 12, but stroke timing was not part of the test.
On November 13, 1986 the lack of timing data was recognized and a
successful timing test was performed.
Containment integrity was never affected by this sequence of events because on November 11 and 12, a manual isolation valve inboard of the valve in question was always closed, and on November 12 and 13, until the condition of the subject valve was verified acceptable, the valve itself was always closed, as was its in-series redundant isolation valve.
Leak test procedures for the waste gas system were enhanced with respect to specifically addressing post maintenance testing following adjustments, with emphasis on containment boundary valves.
Administrative actions were also taken concerning the test personnel involved in the unauthorized adjustments.
In accordance with the NRC Enforcement Policy at
CFR Part 2, Appendix C, certain violations of regulatory requirements are not normally subject to issuance of a formal Notice of Violation providing they meet five criteria.
Such violations must have been: identified by the licensee; reported if required; corrected; determined not to be of major safety significance, and; non-repetitive of previous similar problems for which corrective action proved ineffective.
Of the items
'eviewed above, items a, f, i, j, k, n and p involved apparent violations
C1
meeting these criteria.
In addition, items g, 1, m and o involved findings, during routine surveillance testing, that components or systems being tested did not meet acceptance criteria.
This type of finding indicates required systems or components
~ma have been incapable of meeting regulatory requirements.
Lastly, items b, d, e and o fit a special category of surveillance testing procedure discrepancies identified by an intensive licensee review process in response to enforcement actions involving NRC-identified procedure discrepancies.
h,o violations, deviations, unresolved or open items were identified.
Alle ation As described in I.E. Inspection Reports No. 50-315/86041(DRP);
No. 50-316/86041(DRP),
NRC Region III received an anonymous allegation (Allegation RIII-A-0085) in May, 1986 alleging that the documented test weights on 25 ice baskets had been falsified.
The allegation could not be substantiated at the time, but all the subject testing was repeated with full guality Control Department coverage to develop an uncontested record of ice basket acceptability for subsequent plant operation.
During the current inspection period (ref. Paragraph 7, "Surveillance",
above)
the licensee was performing the first series of ice basket/ice condenser surveillances since the testing associated with the allegation.
As part of two separate containment tours in Unit 2, conducted several days apart, the inspector requested that ice baskets weighed the previous day be re->veighed to verify the documented weights were valid.
On one occasion, a guality Control Department representative was also present.
The gC Department was, in fact, rather e>:tensively involved in review of these activities.
A total of six baskets were re-weighed for the NRC inspector, with all six weights in agreement with their respective documented weights.
The inspector having no further questions concerning this matter, the subject is considered closed.
No violations, deviations, unresolved or open items were identified.
Re ion III and Head uarter Re uests a ~
The NRC Region III office requested that the inspector review the licensee's actions for I.E. Information Notice No.86-104 "Unqualified Butt Splice Connectors Identified In gualified Penetrations",
and provide the information pertaining to unqualified AMP splices to Region III.
The licensee review concluded that the splices discussed in the Notice were not used at D. C. Cook.
This information was provided to Region III.
The licensee did state that TVA had identified a problem with RayChem brand splice seals on cables supplied by Okonite Co. with
"Okoprene" or "Okolon" jackets.
This configuration apparently cannot be qualified for more than two years.
The configuration is used at D.
C.
Cook Units 1 and 2 in circuits located outside the
I
containment.
The licensee has identified each use and has performed an engineering justification for continued operation (JCO) until a suitable inservice cable can be removed and its qualification verified.
This information was also provided to Region III, and is considered an open item pending review by Region III specialists (Open Items No. 315/87007-02; No. 316/87007-02).
b.
The inspector was informed by the NRC Vendor Inspection Branch that cooling assemblies supplied by Tube Turns Corporation, for steam and feedwater containment penetration cooling, may not have been hydrostatically tested.
The inspector was asked to determine if records exist showing the cooling coils installed at D.
C.
Cook were hydrostatically tested.
The licensee's records indicated that the coils were made by a subcontractor for Tube Turns and that the subcontractor hydrostatically tested the coils.
In addition, the licensee hydrostatically tested the coils upon initial installation.
This information was provided to the Vendor Inspection Branch.
One open item and no violations, deviations, or unresolved items were identified.
16.
0 en Items
'I Open Items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both.
An Open Item disclosed during the inspection is discussed in Paragraph 15.a.
17.
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 2.c.
280.
Mana ement Interview The inspectors met with licensee representatives (denoted in Paragraph 1)
on April I, 1987 to discuss the scope and findings of the inspection.
The following items were specifically discussed:
a.
the Unresolved Item (Paragraph 2.c)
and the Open Item (Paragraph 15.a)
b.
the reactor trip signal (Paragraph 4)
c.
the discrepancies in posting of current radiological survey maps (Paragraph 5)
d.
the observations pertaining to controlled procedures (Paragraph 3)
e.
the positive drug screening results (Paragraph 10)
f.
the allegation (Paragraph 14) pertaining to ice basket weighing.
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.
25