IR 05000315/1989034
| ML17325B423 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/13/1990 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17325B422 | List: |
| References | |
| 50-315-89-34, 50-316-89-34, GL-88-17, NUDOCS 9003200191 | |
| Download: ML17325B423 (27) | |
Text
U,S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/89034(DRP);
50-316/89034(DRP)
Docket Nos.
50-315; 50-316 Licenses No.
American Electric Power Service Corporation Indiana Michigan Power Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, Michigan Inspection Conducted:
December 27, 1989 through February 6, 1990 Inspectors:
B.
L. Jorgensen D.
G.
Passehl D.
E. Miller Approved By:
.
L. urg, Chief Projects Section 2A ate Ins ection Summar Ins ection on December
1989 throu h Februar
1990 Re orts o.
50-
89034 RP 0- 16 89034 R
Areas Ins ected:
Routine unannounced inspection by the resident inspectors o
p ant operations; ESF actuations; plant winterization; maintenance; surveillance; emergency preparedness; security; engineering and technical support; reportable events; Bulletins and Generic Letters; and, NRC Region III items.
One safety issues Management System (SIMS) item was reviewed, with the following result:
(Closed) Generic Letter GL-88-17 (MPA No.
L817) concerning loss of decay heat removal.
Results:
Of the ll areas inspected, no violations or deviations were identified.
The inspection disclosed no programmatic weaknesses, but several licensee-identified items were noted which appeared to involve poor work practices or controls.
The inspection noted strengths in the licensee's ongoing assessments of Unit 1 operating performance.
No new Open Items and/or Unresolved Items were identified.
g0032001g1 200313 RDR ADOCK 0%000313 rt PDC
DETAILS Persons Contacted
"A. Blind, Plant Manager
- J. Rutkowski, Assistant Plant Manager, Technical Support
"L. Gibson, Assistant Plant Manager, Projects K. Baker, Assistant Plant Manager, Production
"B. Svensson, Executive Staff Assistant J.
Sampson, Operations Superintendent E. Morse, gC/NDE General Supervisor T.
Bei lman, Maintenance Superintendent J. Droste, Technical Superintendent, Engineering
- T. Postlewait, Design Changes, Superintendent
- L. Matthias, Administrative Superintendent
~J. Wojcik, Technical Superintendent, Physical Sciences M. Horvath, guality Assurance Supervisor D.
Loope, Radiation Protection Supervisor The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
"Denotes some of the personnel attending the Management Interview on February 9, 1990.
0 erational Safet Ver ification (71707 71710 42700 Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant startup, steady power operation, plant shutdown, and system(s)
lineup and operation were observed as applicable.
The performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
The Plant Manager, Assistant Plant Manager-Production, and the Operations Superintendent were well-informed on the overall status of the plant, made frequent visits to the control rooms, and regularly toured the plant.
Evaluation, corrective action, and response to off-normal conditions or events, if any, were examined.
This included compliance with any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verifi.ed.
f
Unit 1 operated at essentially full power throughout the inspection period, establishing and then extending each day, a continuous-run operating record which stood at 214 consecutive days at the end of, the period.
The licensee scheduled the next Unit 1 outage for March 10, 1990.
This would be a
MODE 3 outage only, such that ice condenser lower door surveillance and completion of a deferred hydraulic snubber inspection (among other things)
can be performed.
In discussions on outage scheduling with licensee managers, the inspector questioned Unit 1 performance with respect to unidentified RCS leakage, equipment (e.g.,
reactor coolant pump seals)
trends, inoperable or degraded equipment, etc.
Licensee management was cognizant of these matters in detail and was of the opinion Unit 1 was continuing to operate well without significant degradation of safety or support equipment.
Unit 2 operated routinely at full power from the beginning of the inspection period until commencement of a scheduled MODE 3 surveillance and maintenance outage on January 6,
1990.
A transient RCS radioiodine "spike" (to about 20 percent of the limit) was noted following the shutdown.
This was expected, was well monitored, and appropriate enhanced procedural responses were implemented.
The inspector attended various outage planning and status meetings, observing deliberations on emergent needs (e.g., previously unidentified leaks)
and evaluations of test results.
When the main steam stop valve testing persisted in giving unacceptable results, (see NRC Inspection Reports No. 50-315/90005(DRP);
50-316/90005(DRP))
the licensee decided a
MODE 5 outage would be necessary.
Placing the unit in MODE 5 permitted a number of activities unrelated to the main steam 'stop valve work.
The inspector found the licensee's process for identifying, organizing, and reviewing these items, and its decisions concerning which items to complete, to be effective and conservative.
Not as conservative was the licensee's initial, then perhaps too prolonged, pursuit of means whereby cooldown to MODE 5 could be avoided.
As mentioned above, those items are addressed in the above referenced inspection report.
The Unit 2 outage ended on January 25, 1990, with the reactor critical at ll:36 a.m.
and the generator, paralleled at 10:53 p.m.
The inspector performed a partial walkdown of the Unit 2 reactor coolant system (RCS) pressure boundary during the scheduled MODE 3 surveillance outage which occurred during this inspection period.
Particular attention was directed to the locations of previously known small leaks, including safety injection loop check Valves 2-SI-158-Ll and 2-SI-158-L4.
Unidentified Unit 2 RCS leak rate had been approximately 0.2 gpm and steady for the last several months of plant operation.
The subject valves both showed indications of continued small leakage:
boric acid residue; wisping of steam; observable dripping.
These were in small amounts consistent with
the previous valve history.
The licensee decided to attempt leak repair on the dripping (-Ll) valve only, and succeeded in reducing, but not eliminating, leakage.
Subsequently, when a cooldown to MODE 5 was required for unrelated reasons, the licensee reduced RCS level to "half loop" (see Paragraphs 2. d and ll.a (10)) and completed repairs which eliminated these leaks.
d.
Other items inspected included an overview of the RCS piping in general, reactor coolant pump and reactor vessel head stud regions, and the incore detector thimble tube seal table.
No indication of leakage was noted in any of these areas.
The Unit 2 reactor coolant system (RCS) was drained to half loop on January 14, 1990, to permit repairs on minor leaks affecting some low pressure safety injection system check valves.
A few hours after half loop was reached, relatively minor and infrequent fluctuations in the East Residual Heat Removal (ERHR) pump motor amperes were observed, coincident with momentary pump discharge pressure perturbations.
Air entrainment was suspected, and RHR system flow was reduced to suppress vortexing effects.
Ampere fluctuation was still observed, and RCS level was raised.
Operator actions of manipulating RHR flow and RCS level failed to stabilize the situation completely.
The event was brought under control some six hours'after the outset by venting of the RHR pump suction line.
The circumstances surrounding this event are discussed further below, as part of the inspection of Generic Letter 88-17,
"Loss of Decay Heat Removal,"
Paragraph ll.a(10).
e.
The following Problem Reports were reviewed:
Problem Re ort PR 90-0053:
Operations performed part of its own Survei 1 lance est 2-OHP 4030 STP. 019F, involving stroke-timing main steam stop valves, without first completing a Plant Manager'
Standing Order (PMSO-113) procedure review.
The PMSO specifies that two Senior Reactor Operator (SRO) licensed personnel shall determine the surveillance test avoids cross train problems.
Several hundred test procedures have been or will be subjected to this one-time special review.
Thus far, the subject Problem Report constitutes the third example of failure to perform the review before using the procedure.
When the review was performed, no cross-train problems were noted.
Problem Re ort PR 90-0072:
An isolation valve to one of two parallel emergency diesel-generator control air dryers was found sealed in the closed position rather than in the open position.
The error occurred about 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> earlier on the day of discovery, when a test was performed on the diesel.
The test procedure specified return to normal (open) position on the valve, and included an independent verification.
Thus, this finding showed two independent errors occurred.
At the conclusion of the inspection, the annual
sel f-appraisal within the Operations Department, concerning valving or other control manipulation errors (generally only a handful per year)
was in its final stages of preparation.
No violations, deviations, unresolved or open items were identified.
Reactor Tri or ESF Actuations (93702 A Unit 2 Engineered Safety Features actuation (emergency diesel-generator auto-started and loaded)
occurred at 6:12 a.m.
on January 12, 1990, with the unit in MODE 5.
An instrument calibration was in progress which involved lifting of leads.
As one lead was unscrewed and withdrawn, it slipped free and contacted an adjacent terminal, causing a short of the trip contacts for the T21D bus tie breaker.
This breaker opened and de-energized the bus.
This is not the normal bus supply breaker with the unit in service.
When Bus T21D went dead, Emergency Diesel-Generator 2CD auto-started and loaded as designed.
No violations, deviations, unresolved or open items were identified.
Plant Winterization 71714)
The licensee's implementation of protective measures for equipment subject to extreme cold weather was evaluated.
Job Orders A004999 and A005000 documented plant winterization performed via "electrical" and "general" tasks respectively.
The guidance for the specific tasks was described in Licensee Procedure MHI 5030, Task Sheet 30, "Plant Winterization."
Many of the areas where cold weather protection was important for safe plant operation, such as the refueling water storage tank valve house, were inspected to ensure the presence of space heaters, heat tracing, etc.,
and that the required heaters were operating properly.
Not all areas of the plant remained adequately protected, however, as evidenced by the submission of Condition Report (CR) No. 2-12-89-2103, which documents discovery of a frozen instrument line for the nonessential service water supply to No.
21 reactor coolant pump motor air cooler.
Factors contributing to the freezing of the line were a faulty heating steam coil and a direct opening to the outside (for ventilation purposes)
while painting.
Job or ders wer e written to repair the heating coi 1, and the instrument line indicated properly.
The inspector interviewed the supervisor in charge of winterization at the plant who had several ideas about improving the program.
One called for use of guillotine-type covers over selected louvered openings for use on days when'inter temperatures averaged above normal.
Lastly, a situation was discovered where a heat trace circuit was added without apparent authorization (i.e.,
no documentation)
to a section of fire protection water piping adjacent to the Unit 2 Turbine Building Crane Bay.
Apparently, the added heat trace, about 18 feet, was installed as freeze protection.
The power panel circuit directory was revised and
associated drawings were updated.
The circuit is evidently needed and no removal is planned.
No violations, deviations, unresolved or open items were identified.
5.
Maintenance 62703 42700)
Maintenance activities in the plant were routinely inspected, including both corrective maintenance (repairs)
and preventive maintenance.
Mechanical, electrical, and instrument and control group maintenance activities were included as available.
The focus of the inspection was to assure the maintenance activities reviewed were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specifications.
The following items were considered during this review:
the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The following activities were inspected:
Job Order JO 8007387:
Annual preventive maintenance
- disassemble, clean, inspect and repair as needed
.
.
.."
The maintenance was performed on the Unit 2 control air compressor.
The documentation of work performed appeared satisfactory, and the men doing the work seemed knowledgeable of the equipment.
However, parts were not identified and staged in advance of this job.
When the inspector asked to see the job order, he was informed another individual was using it to track down parts.
b.
Job Order JO 8013093:
Inspect and repair/replace internals as necessary on Valve 2-ESW-102W (2W Essential Service Water pump discharge check valve); valve "sticks" and "slams" when ESW Pump 2W is shut off.
This activity utilized Procedure
- 12 MHP 5021.001.021,
"Disassembly, Repair, and Reassembly of Centerline 'Split Center'pring Loaded Check Valves," which was present at the job site.
During one inspection of this job, the inspector found that Procedure Step 7. 2. 8, which documents supervisory inspection of the internals, had not been signed off, but reassembly had progressed to a point wh'ere. the valve internals could no longer be inspected.
The subject supervisor was encountered in the turbine building shortly thereafter, enroute to the job site to perform the signoff.
He explained that he had performed the visual inspection earlier, but had postponed signing off unti 1 he could confirm that newly-installed springs, which were not Class 30 (nuclear safety specification),
were not required to be Class 30.
The inspector was shown an engineering specification letter which confirmed that the newly installed springs were correct.
The supervisor stated he intended to place this letter
in the Job Order package first, then sign off on the approving internal inspection.
The NRC inspector had no further questions on the matter.
C.
Job Order JO B012013:
"2-MRV-212 leaks by - repair as necessary."
The subJect valve ss the "B" train dump valve for main steam stop Valve 2-MRV-210.
Leakage past the dump valve apparently contributed to slow stroke timing of the stop valve as discussed in NRC Inspection Reports No. 50-315/90005(DRP);
50-316/90005(DRP).
The repair was performed to Procedure
~"12 MHP 5021
~ 001.075,
"Repair Procedure for Fisher Controls Angle Valves."
Job Order JO B006833:
Repair body-to-bonnet leak on main steam lead No.
3 to Aux) lunary Feed Pump Turbine shutoff valve, 2-MCM-231.
On one inspection of this activity, the repairmen were absent on a break and only the assigned fire watch was in the area.
The open valve housing had not been covered for cleanliness as suggested in the procedure.
However, because the work involved internal cutting, a cloth had been stuffed inside (below the cutting area) to catch filings.
A maintenance supervisor entered the area just after the inspector and, noting the same condition, placed a cover cloth over the opening.
He stated he would also counsel the workers.
e.
Several Problem Reports were noted as potentially indicative of poor maintenance work practices, including:
(1)
Problem Report 90-0101 involved apparent improper reassembly of Valve 2-RC-108-L4 (RTD bypass loop isolation valve) after leak repair, such that the leak was worse.
(2)
Problem Report 90-0111 involved potentially overtorquing of a Unit 2 pressurizer safety valve stud.
(3)
Problem Report 90-0120 involved finding a "stray" medium-size carbon steel nut inside Unit 2 Valve 2-HARV-303 (letdown to VCT/divert valve) which had caused valve misoperation.
These matters were discussed at the Management Interview.
No violations, deviations, unresolved or open items were identified.
6.
Sur vei 1 Vance 61726 42700 The inspector reviewed Technical Specifications required surveillance testing as'~described below and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were properly accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that deficiencies identified during the testing were properly reviewed and resolved by appropriate management personne The b.
following activities were inspected:
""1 THP 4030 STP.411,
"Reactor Trip SSPS Logic and Reactor Trip Breaker Train 'B'urveillance Test (Monthly)."
THP 6040 PER.323,
"Flux Map and Thermocouple Map Data Collection."
c
~
d.
- 2 THP 4030 STP. 113, "Pressurizer Pressure Protection Set III Surveillance Test (Monthly)."
- "2 THP 4030 STP. 124,
"Source Range Nuclear Instrumentation Protection Set II (N-32) Surveillance Test."
e.
The inspector noted a guality Control group representative was also present and auditing this activity, including a step-by-step verification being documented on his own copy of the procedure.
- ~1 OHP 4030 STP.018,
"Steam Generator Stop Valve Dump Valve Surveillance Test."
This surveillance was performed on each t
MSSV after each pressure decay test to prove MSSV operability (Ref.
NRC Inspection Reports No.
50-315/90005(DRP);
50-316/90005(DRP)).
The test was specifically observed on 1-MRV-220.
- 12 THP 4030 STP.211 (Rev. 17), "Ice Condenser Surveillance."
The inspector observed Unit 2 ice basket weighing which the licensee.
performed to verify ice condenser operability.
Of the 204 randomly selected baskets weighed by the licensee, 12 were weighed under NRC observation.
Included in the sample of 12 were 4 baskets selected by and specially reweighed at the request of the inspector.
None of the reweighed baskets had weights exactly equal to previously recorded values, but all were considered sufficiently close as to validate the authenticity of the original weighings.
A number of completed data sheets for other baskets were reviewed and no problems were identified.
A couple of observations were made on the way to containment to watch the surveillance.
The laminated plate at the card reader outside the containment, which gave the number of the control room to call prior to entry, was incor rect.
The number reaches a phone in the-back of the control room, and when the inspector called he was informed he had the wrong number.
Additionally, phone numbers for radiological personnel, job coverage personnel, etc.,
were scribbled on the wall at the base of the ramp leading to the containment entrance.
Finally, no dose rate meters were available for about twenty minutes as the meters were being source checked.
This was discussed with appropriate RP department supervisors and again at the Management Interview.
Two Problem Reports, both involving Unit 1 surveillance by the instrument group, describe failure of plant operators to implement compensatory surveillance as specified by plant Technical Specification 4. 1. 1.5.b.
The Problem Reports were No. 89-1144 and
89-1223 and involved a requirement to manually monitor and log the lowest reactor coolant system loop average temperature whenever the low temperature alarm is inoperable, as it was due to instrument group testing.
It is expected this matter will be reviewed further upon receipt of the anticipated Licensee Event Reports.
No violations, deviations, unresolved or open items were identified.
7.
En ineerin and Technical Su ort The inspector monitored engineering and technical support activities at the site and, on occasion, as provided to the site from the corporate office.
The purpose of this monitoring was to assess the adequacy of these functions in contributing properly to other functions such as operations, maintenance, testing, training, fire protection and configuration management.
The following Problem Reports were of note:
a.
Problem Re ort PR 90-0054:
"The Unit 2 P-250 high, low, and incremental alarm setpoints of the control and shutdown rods are incorrect."
The inspector interviewed Computer Science Department supervisors who indicated this was not a safety concern, as the P-250 does not supply signals to the reactor protection system for rod insertion limits, withdrawal limits, and sequencing.
The supervisors stated the operability of the P-250 was not a concern since the P-250 alarm setpoints noted above represented a capability of the P-250 that is not used.
b.
Problem Re ort (PR) 90-0096:
"A come-along was rigged (separately)
from the bonnets of 2-MRV-210, 240, and 230 to a 1-inch pipe
.
to pull 3-inch piping together for a weld fitup without prior engineering approval."
This was performed in conjunction with maintenance activities surrounding the Unit 2 main steam stop valve modification (NRC Inspection Reports No.
50-315/90005(DRP);
50-316/90005(DRP) ).
C.
Problem Re ort PR 90-0102:
"Failure rate on primary water flush valve diaphragms to suction of boric acid transfer pumps has been increasing in frequency...
adverse trend."
The problem report also noted that job orders were written on surrounding valves being extremely hot to the touch, possibly indicative of heat tracing or insulation problems.
The question was also raised whether the rubber material in the diaphragm valves was suitable to the media and temperatures involved.
A related condition report surfaced approximately two weeks after the subject problem report was written; this was to document primary water leaking from a diaphragm valve which isolates suction to the No.
1 boric acid transfer pump.
Work was begun to repair two primary water flush valves on February 6, 1990.
No violations, deviations, unresolved or open items were identifie.
Emer enc Pre aredness (82201 82203 Event classification and reporting relating to a Unit 2 "Unusual Event" of January 11, 1990, were reviewed.
The event involved an administrative declaration that all four Unit 2 main steam stop valves were inoperable in MODE 3.
This occurred at 9: 16 a.m.
and required unit shutdown to MODE 5 as discussed elsewhere in this report.
Classification and reporting of this event were both considered proper by the inspector.
No violations, deviations, unresolved or open items were identified.
Securi t (71707)
Routine facility security measures, including control of access for vehicles, packages and personnel, were observed.
Performance of dedicated physical security equipment was verified during inspections in various plant areas.
The activities of the professional security force in maintaining facility security protection were occasionally examined or reviewed, and interviews were occasionally conducted with security force members.
One area of security specifically inspected was pertained to the licensee's Fitness For Duty policy as discussed in Paragraph 12.a.
No violations, deviations, unresolved or open items were identified.
10.
Re ortable Events 92700 92720 The following item was of note:
The resident office was informed of a notification by the licensee to the NRC (Regional and Headquarters Offices) on January 5, 1990, made in accordance with 10 CFR Part 21, concerning the potential for all models and sizes of Westinghouse Class lE thermal/magnetic molded case circuit breakers performance characteristics to deviate from published information.
The problem was discovered by the licensee when such a breaker, installed in a non-Class lE motor start circuit, tripped open during attempts to start the motor.
Subsequent testing by Westinghouse and D.C.
Cook personnel',confirmed the non-conformity of the breakers.
An information copy of the notification was forwarded to all nuclear utilities.
This 10 CFR Part 21 Report will be tracked as an Open Item (315/90001-PP; 316/90001-PP)
pending resolution.
No violations, deviations or unresolved items were identified.
One Open Item (315/90001-PP; 316/90001-PP)
was identified.
11.
NRC Com liance Bulletins Notices and Generic Letters 92703 The inspector reviewed the NRC communications listed below and verified that:
the licensee has received the correspondence; the correspondence
was reviewed by appropriate management representatives; a written response was submitted if required; and, plant-specific actions were taken as described in the licensee's response.
a.
"Loss of Decay Heat Removal," dated October 17, 1988.
As noted in Paragraph 2.d above," Unit 2 was placed in MODE 5 (Cold Shutdown) with reduced Reactor Coolant System (RCS) inventory, from January 14-18, 1990.
This inspection therefore included a review of the elements described in the NRC Inspection Manual, Temporary Instruction TI 2515/101, for follow up on the subject Generic Letter (GL).
(1)
The inspector reviewed the licensee's GL 88-17 documentation file, including:
the Generic Letter itself; licensee internal meeting notes concerning specific assignment of responsibilities for "Expeditious Action" items; official licensee responses through AEP:NRC: 1033C dated February 6, 1989; gA surveillance comments on evaluation of commitments in the response letters; responses to the gA findings; NRC Office of Nuclear Reactor Regulation (NRC:NRR) comments on the response letters, and; miscellaneous other supporting materials As the licensee's response actions appeared to meet the intent of the Generic Letter, the major emphasis of the inspection was on implementation.
(2)
The inspector reviewed licensee actions in the area of ~Trainin
.
Training as recommended by GL 88-17 was complete for operat>ons personnel and for members of the Plant Nuclear Safety Review Committee (PNSRC)
~
Specific training on the Diablo Canyon event was not originally provided to the mechanical, electrical and instrument maintenance personnel, but such training was completed during this inspection.
This satisfied a gA-initiated finding and NRC:NRR comment that such training should be provided to all personnel who can affect operations at reduced inventory.
Interviews with operations personnel established that they were well-versed in the issues and concerns raised in the Generic Letter.
(3)
The inspector reviewed license actions in the area of Containment Closure.
The licensee had prepared, reviewed and approved procedures with criteria for initiation of containment closure and definition what constitutes prerequisite closure status.
These procedures appeared capable of properly initiating, achieving and verifying timely closure.
(4)
The inspector reviewed licensee actions in the area of Tem erature Indications.
The two stipulated independent, continuous temperature indications for core exit temperature are provided by existing core exit thermocouples.
These may be monitored on either of two computer system (5)
(7)
The inspector reviewed licensee actions in the area of RCS Mater.Level Indications.
Two systems are provided:
a "visual level instrument cons>sting of a sight glass monitored by a TV camera, and; an "electronic level "indicator."
The latter includes an alarm function.
8oth provide indication in the main control room.
The two systems are not "independent" inasmuch as they share a
common tap.
Common-mode failure probability is kept low by well-controlled installation and inspection techniques, governed by a new procedure specific to that purpose.
The inspector reviewed licensee actions in the area of RCS Perturbations.
Procedural controls existed to address operations that could perturb the RCS or associated systems while in reduced inventory conditions.
No such perturbations were contemplated during the reduced inventory period, January 14-18, but some indications were noted involving perturbations in the amperage drawn by the operating decay heat removal pump.
These were documented and followed up pursuant to Problem Report No. 90-0080, which is discussed further in Section 10 below.
They were not due to inadequate control of activities with potential to perturb level.
The inspector reviewed the licensee's actions in the area of RCS Inventory; specifically, the maintenance of two means of adding water to the RCS with flow through the reactor vessel.
These measures have been proceduralized.
During the January 14-18, 1990, half-loop operations, a centrifugal charging pump (which is one specified flow path)
was successfully used for inventory addition to increase RCS level when desired.
(8)
The inspector reviewed licensee actions in the area of ~Hot Le Flow Paths, verifying that the licensee has procedures to prevent >nstallation of all four hot leg nozzle dame without a specified, adequate vent path to prevent upper vessel plenum pressurization.
The licensee had not used nozzle dams for several years, and did not contemplate their future use, but nozzle dam installation procedures still existed.
These were placed on administrative hold to assure insertion of venting instructions prior to any possible future use of the nozzle dams.
(9)
(10)
No review was conducted concerning Loo Sto Valves, as the D.C.
Cook plant is not equipped with such valves.
As noted in (2.d) above, there were instances of amperage perturbations associated with the operating residual heat removal (RHR) pump.
Normal operating current is on the order of 35-40 amps.
Fluctuations of plus/minus about 5 amps were first observed very early (12:20 a.m.)
on Januaey 15, 1990, and recurred occasionally thereafter, at various levels and
flow rates near "half loop."
They were never continuous and did not appear to represent a threat to the operating pump, but they were unexpected.
Problem Report No. 90-0080 documented the conditions observed, the follow up investigation, and the corrective actions.
The Operations Department initiated an investigation with assistance from Engineering.
The inspector attended a critique of the event on January 18, 1990, the results and recommendations of which will be documented in a report tentatively to be completed the middle of February 1990.
The inspector had no further questions concerning the "expeditious actions" portion of the licensee's program in response to Generic Letter 88-17; review of that part of the issue is considered CLOSED.
b.
NRC Bulletin 88-04 (updated),
"Potential Safety Related Pump Loss."
In NRC Inspection Reports No.
50-315/89021(DRP);
50-316/89021(DRP),
Paragraphs 3.d and 10.b, a Condition Report (No. 12-06-89-1171)
was discussed involving a disparity between the Unit 1 East and West Motor Driven Auxiliary Feedwater Pumps (MDAFP).
A review of surveillance tests at that time revealed the West pump had higher discharge pressure than the East.
The two pumps share an emergency leakoff line, and a concern was raised over the adequacy of the East pumps'eakoff (mini-flow) with both pumps in service.
The licensee supplemented their response to the NRC Bulletin by letter dated December 11, 1989 (AEP:NRC: 1065B) to address the potential for adverse pump-to-pump interaction for the MDAFPs.
The short term corrective action described in the letter indicated applicable procedure revisions (to include cautionary statements)
would be completed by March 1990.
. The inspector expressed the concern that since Unit 2 had an outage scheduled in January 1990, special consideration should be given to promulgating short term corrective actions on an accelerated basis.
The licensee responded with a number of actions, including:
(1)
a memo from the Operations Department Supervisor to Shift Supervisors directing them to pay special attention to the MDAFP flow retention valves while both pumps are running; (2)
special pre-shutdown and startup briefings attended by the Shift Technical Advisors (STAs);
(3)
shift turnover discussion notes amplifying the subject; and (4)
operator aids (plaques)
posted on the control board.
No violations, deviations, unresolved or open items were identified.
12.
Re ion III It'ems 92705)
Sy letter dated December 8, 1989, from E.
G.
Greenman, Director, Division of Reactor Projects, the inspector was requested to attend selected licensee Fitness For Duty (FFO) training sessions to determine whether required training is being conducted.
The inspection guidance is contained in NRC Inspection Manual TI 2515/104, dated November 27, 1989.
One session of the FFO policy awareness training was observed for each group of general employees, supervisors, and escorts.
A questionnaire was completed for each session, assessing whether certain areas (such as the effects and hazards of drugs and alcohol and the role of the employee assistance program)
were addressed.
The Division of Reactor Inspection and Safeguards, NRR has been assigned the responsibility to evaluate and assess the information in the questionnaires from all reactor sites.
b.
On January 18, 1990, Mr.
H. J. Hiller, Director, Division of Reactor Safety, Region III, toured the D.C.
Cook facility accompanied by other members of the Region III staff.
His observations and notes are included as an attachment to this report.
No violations, deviations, unresolved or open items were identified.
13.
Iodine U take Event Preliminar Review IP 92701)
NRC Region III was informed by the licensee on January 8, 1990, of the occurrence of minor uptakes of iodine-131 by a number of workers in the Unit 2 containment between January 6-9, 1990.
A regional radiation specialist visited the site on January 10, 1990, to review the radiological aspects of the event.
The review confirmed that about 60 individuals received iodine-131 uptakes in the range of five to ten nanocuries with none indicative of intakes greater than five HPC-hours.
The exposed individuals were working in both upper and lower containments performing maintenance and surveillance tasks while the reactor was in Mode 3.
The individuals in lower containment wore particulate respirators or forced air particulate filtered hoods; those in other parts of containment wore no respirators.
The licensee's pre-job air samples from both upper and lower containment were below 25 percent of MPC for iodine-131.
Many grab air samples were taken in lower containment while work was in progress; a few showed iodine above MPC-levels.
The exposures to individuals working outside of lower containment were unanticipated and may have resulted from unexpected and uncoordinated operation of containment ventilation systems.
The licensee's ongoing investigation of this event is looking into these matters as well as other matters bearing on the adequacy of radiological controls.
This matter will be examined further by a NRC Region III radiation specialist during a future inspection.
(Open Item 316/89034-01)
14.
Mana ement Interview (30703 The inspectors met with licensee representatives (denoted in Paragraph 1)
on February 9, 1990, to discuss the scope and findings of the inspection.
In addition, the inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee did not identify any such documents/processes as proprietary.
Attachment:
Memo, H. Miller to A. Oavis dated January 29, 1990
~gR 466'
Op n
NUCLEAR REGULATORY COMMISSION
REGION III
799 ROOSEVELT ROAO GLEN ELLYN, ILLINOIS 60137 Jnv 29 19I30 MEMORANDUM For:
A. Bert Davis, Regional Administrator FROM:
SUBJECT:
H. J. Hiller, Director, Division of Reactor Safety TRIP TO D.C.
COOK On January 18, 1990 I toured the D. C.
Cook plant and participated in the exit meeting for the recently completed maintenance team inspection (HTI).
Attending the exit meeting for American Electric Power (AEP) were Hr. Dave Wi lliams (Senior Vice President for Engineering and Construction),
Hr. Hilt Alexich (Vice President Nuclear Operations),
Hr. A. Blind, plant manager and numerous other site and AEP corporate staff.
This memo summarizes very briefly the results of the HTI and my observations in touring the plant.
The HTI identified numerous problems with maintenance activities at D. C. Cook.
Both the number and kind of weaknesses found in the inspection place Cook clear ly at the bottom end of the spectrum of plants assessed so far in Region III. I told AEP the results were more negative than the last SALP which was completed about seven months ago.
The findings will of course be presented in the inspec-tion report but, briefly, some of the more significant findings were:
Inadequate preventive maintenance program. 'he team identified a number of important components that had not received adequate preventive maintenance.
This included checks for condition of lubrication of 4 kV ECCS breaker operating mechanisms recommended by the vendor; in this case, the breakers experienced numerous failures due to hardening of lubricants.
A "replace it when it breaks" attitude seems to prevail.
Procedures for maintenance are very poor or nonexistent in many cases.
This is particularly true in the BOP area.
This included the case of service water pump motors which have repeatedly required rework; a maintenance procedure does not exist for these pumps.
There were numerous instances where procedures were not followed or not used while performing the activity (e.g., special procedures required for racking out reactor trip breakers).
There has been virtually no trending of equipment problems and root cause analysis of failures.
This results from several things.
Records of maintenance and equipment histories are very poor.
Formal programs for trending of maintenance have not been employed (the licensee has just initiated a program in,the I8C area).
The systems engineer concept has just been initiated at D.C.
Cook on a very limited basis and there does not appear to be any other significant engineering involvement in this are A. Bert Davis
.)At; 29 890 The current backlog of corrective maintenance is excessive.
There are about 1800 non-outage job orders which is far beyond Cook's goal of 850.
It constitutes more than four months of work.
Work planning and scheduling has not been integrated to minimize the amount of time equipment is taken out of service for various corrective and preventive maintenance activities.
Material condition was poor as evidenced by numerous leaks in the auxiliary building and other areas of the plant (e.g., diesel generator room).
Many of these items were not identified for corrective maintenance by the licensee.
The licensee identified many of the problems identified by the team about two years ago in its maintenance self-assessment but management involvement to assure these problems were corrected has been weak.
(In fact, many of the problems were closed out by management and had to be reopened based on recent findings of INPO and the team.)
This raises concern over whether management wi 11 mount a sustained, serious effort to deal with the weaknesses that we have pointed out.
Related but separate problems were noted with respect to fuse control and similar engineering support functions, electrical maintenance quality control involvement, establishment of specific goals for measuring effectiveness of maintenance in many areas, and material control and availability of spare parts.
I indicated that, because many of the findings such as the one on trending were not tied to some specific regulatory requirement, we were available to discuss them as they needed.
I said that, in any case, we would be following up on our inspection findings because of our concern.
The plant tour focused mainly on the auxiliary building.
I was accompanied by Bruce Burgess and the resident inspectors, Bruce Jorgensen and Dave Passehl.
The following was noted:
Many of the less traveled spaces are very poorly lighted, unpainted and not very clean.
One example is the penetrations room which contains, among other things, AFW discharge piping and valves.
Portable lighting has to be brought in to do any work in these areas.
The normal lighting conditions make inspection of the spaces and identification of possible problems difficult.
Work being performed on the MSIVs that recently experienced stroke time problems appeared to be poorly controlled.
Cables were tied back from the work area using rope attached to some safety related instrumentation equipment.
In detaching control cabling to the valve, little care was taken to avoid pulling the armored jacket from its connections so as to
A. Bert Davis twit w J I
jt
protect wire insulation.
While the job was not completed, the areas under and around the valves appeared to excessively dirty.
(Bruce Jorgensen said this job revealed some of the same weaknesses observed by the NTI.
AEP found after beginning the job that there were interferences which were not anticipated and which had to be removed.
A section of grating which provides structural support for the HSIV had to be cut out.
This was done by workers on the spot without any clearance from engineering.
It turns out that the same thing was done the last time the valves were worked on about seven years ago but nothing was documented at that time to support future maintenance.)
There was a lot of clutter in the aux building.
In many areas there were barrels, welding machines, scaffolding, sweeping equipment, boxes, etc.
This issue has been pursued in the past with the licensee by Bruce Jorgensen and, in response, the licensee has instituted a program to "evaluate and control" storage of such equipment and materials.
However, as a practical matter it appears that they have merely institutionalized this situation since the amount of material has not decreased significantly.
Allowing for the active construction that was going on, this situation still appeared to be worse than existed in my previous visits to Cook.
Several large boxes containing worn out, mildly contaminated pump impellers have been moved from one location to another under this system for several years.
I have several concerns with this situation.
First, such material may, if not controlled, damage safety related equipment during a seismic event.
Bruce Jorgensen is checking to assure that this is considered by the licensee in evaluating each individual situation.
Secondly, this kind of situation can contribute to lax attitudes about plant appearance and material condition.
There were numerous yellow rad control bags and hoses to contain leaks.
Hany appear to be "preventive" in nature, but it appeared to indicate there was leakage on a large number of valves and fittings (of approximately 400 bags and hoses, over 200 had job orders to fix leaks).
Hoses were run in some instances long distances across the floor to drains without adequate markings.
There were several significant steam leaks in the area of the steam generator flash tank and blowdown system.
One blowdown system valve leak was directed towards a radiological leakage control bag which was totally ineffective in containing the leak.
(The catchment may not have been needed strictly speaking given'the likely small, if not undetectable amounts of radioactivity in the steam generator secondary side.)
Overall, while the turbine building upper level appeared to be well painted and clean, the rest of the plant does not compare well with most plants in the region in terms of cleanliness and physical appearanc A. Bert Davis JAN 29 1990 I talked to several operators.
Each said that operator morale was good.
There is some mild consternation among a minority of operators who did not vote in favor of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift rotation scheme that is to be tried at Cook in the near future.
Hone of the individuals with whom I.spoke participated in the recent HRC administered requalification exam; but somewhat on the positive side, they said there had been no complaining about the exam as there has been in the past with these exams.
Two operators said that they were reasonably comfortable with plant equipment reliability.
One operator voiced the opinion that it took too long to fix some problems (such as control room recorders), partially due to spare parts and logistics problems.
It was difficult to judge the numbers of problem control room annunciators given plant startup on one unit and surveillance testing on the other.
Dave Williams said that in appointing Al Blind to the plant manager position, they made upgrading maintenance one of the two top priorities.
The results of the MTI and my site tour give rise to concerns that we must follow very closely actions being taken by AEP to remedy the problems noted.
We intend to devote resources to this effort.
In addition to making it the focus of management meetings, working with DRP, we will develop a followup inspection plan.
Consid-eration will be given to assigning a lead DRS inspector having responsibility for following this situation and possibly providing augmented site coverage in the maintenance area on a periodic basis.
cc:
C. J. Paperiello, RIII E. G. Greenman, RIII C. E. Horelius RIII J.
W. Clifford, EDO T. O. Martin, RIII R.
W. Cooper, RIII G. C. Wright, RIII J. Miller, Director ivision of Reactor Safety