IR 05000315/1989002
| ML17326B545 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 02/27/1989 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17326B543 | List: |
| References | |
| 50-315-89-02, 50-315-89-2, 50-316-89-02, 50-316-89-2, IEB-88-011, IEB-88-11, NUDOCS 8903090427 | |
| Download: ML17326B545 (26) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/89002(DRP);
50-316/89002(DRP)
Docket Nos.
50-315 50-316 Licenses No. DPR-58; DPR-74 Licensee:
American Electric Power Service Corporation Indiana Michigan Power Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, Michigan Inspection Conducted:
December 28, 1988 through February 7,
1989 Inspectors:
B. L. Jorgensen D.
G. Passehl M. J.
Farber g4'P Approved By:
. L. Burgos, Chief Projects Section 2A Date Ins ection Summar Iris ection on December 28, 1988 throu h Februar 7,
1989 Re orts No. 50-315/89002 D P; 50-316 89002 DRP
.
of:
actions on previously identified items; plant operations; reactor trips; radiological controls; maintenance; surveillance; fire protection; emergency preparedness; outages; safety assessment and quality verification activities; Bulletins; and Allegations.
No Safety Issues Management System (SIMS) items were reviewed during this inspection.
Results:
Of the 12 areas inspected, no violations or deviations w'ere identified in 11 areas.
One violation was identified (Level IV - equipment post-maintenance procedure controls not followed - Paragraph 6.f) in the remaining area:
I The inspection noted no new notable strengths or weaknesses.
The licensee continued to aggressively pursue resolution of NRC questions or concerns with potential D.C.
Cook plant applicability.
A new Open Item was identified (and is discussed in Paragraph 6.e)
in the area of maintenance procedure clarity.
8903090427 890228 PDR ADOCK 050003i5 G
PNU
DETAILS 1.
Persons Contacted
- W.
A.
- J
- L B.
K.
J.
E.
T.
J.
- T L.
- J M.
- D
- B
- S
- J
- M.
- D Smith, Jr., Plant Manager Blind, Assistant Plant Manager, Administration Rutkowski, Assistant Plant Manager, Production Gibson, Assistant Plant Manager, Technical Support Svensson, Licensing Activity Coordinator Baker, Operations Superintendent Sampson, Safety and Assessment Superintendent Morse, gC/NDE General Supervisor Beilman, 18;C/Planning Superintendent Droste, Maintenance Superintendent Postlewait, Technical Superintendent, Engineering Matthias, Administrative Superintendent Wojcik, Technical Superintendent, Physical Sciences Horvath, equality Assurance Supervisor Loope, Radiation Protection Supervisor Worm, Operations Performance Supervisor Wolf, AEPSC Site gA Auditor St.
Amand, Performance Engineer Supervisor Stark, Performance Electrical Supervisor Krause; IKC Regulatory 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 Management Interview on February 9,
1989.
2.
Actions on Previousl Identified Items (92701, 92702)
a ~
b.
Closed 0 en Item (316/83004-04):
Develop testing to validate spray a
itive system opera i ity ca culations and provide a correlation between pre-op and periodic tests.
As updated in NRC Inspection Report No. 050-315/88023(DRP)
for this item, and in Inspection Report No. 050-316/88028(DRP)
for a companion item, the final licensee action on the matter was to describe the revised future testing procedure for review by the NRC Office of Nuclear Reactor Regulation (NRR).
The licensee submitted this information for NRR review with its letter (AEP:NRC:0914F)
dated January 10, 1989.
(Closed)
Unresolved Item (315/88023-03:
Evaluate cause(s)
of pro ems wit oric aci owpat s
uring Unit 1 shutdown of October ll, 1988.
The licensee's evaluation, which supported closure of Problem Report No.88-730, determined that the normal "borate" flowpath was blocked by solidified boric acid.
This was a result of a partial failure of heat trace tape, combined with (and perhaps caused in part by)
a deferral in replacing insulation to permit a
c ~
Code specified visual leak check after maintenance.
When the heat tracing and insulation were repaired, the flow blockage dissolved away.
The "emergency borate" flowpath was apparently not actually blocked, but it did not immediately indicate flow when first aligned.
After the pumps and valves were cycled, the "emergency borate" path was successfully used and indicated flow.
Closed) Violation 316/88028-01):
Failure to post or maintain a
required fire watch for hot work" involving welding of a Unistrut attachment on steam generator No. 21.
The licensee's letter (AEP:NRC: 1060M) dated January 4,
1989 describes corrective and preventive actions.
These actions, which have been verified by the inspector, were considered satisfactory to address the inspector's concerns associated with this violation.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Verifi.cation 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.
'he performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use. and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
Evaluation, corrective action, and response for off normal conditions or events, if any, were examined.
This included compliance to any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor ptotection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
a.
Unit 1 operated routinely at power during the inspection period, except for a brief outage following a reactor trip (see Paragraph 4)
on January 16, 1989.
In order to extend the current operating cycle till after the planned startup of Unit 2 in February 1989 (see Paragraph
'0) power level was being held at 70-percent full power.
b.
The inspector performed a walkdown of the starting air system for the 2AB emergency diesel generator using DATA/SIGNOFF SHEET 5. 1 of Procedure 2-OHP 4021.032.004
"Placing Emergency Diesel Generator Starting Air System In Service."
Licensee drawing OP-2-5151B was
also used in the walkdown.
Further, a comparison was made against DATA/SIGNOFF SHEET 5.2 for the 2CD diesel.
All valves were found configured as specified on the checklist.
The following were also noted:
i)
the tag for Valve 2-DG-136A was missing; ii)
the 2AB diesel checklist specifically enumerates two air dryer drain valves while the 2CD diesel checklist calls for a check of a single, unnumbered valve, and; iii) there were minor inconsistencies in nomenclature among the checklists and valve tags.
The above observations were provided to the Operations Department for consideration.
Restoration of a "clearance" (No. 207582)
on emergency diesel 2AB was specifically observed in part.
Five air start system valves were involved, and the inspector witnessed correct positioning,
"Danger" tag removal, and (in the three applicable cases)
placement of new valve seals.
The valve seal serial numbers were observed to be accurately recorded for future periodic verifications.
On December 24, 1988, the licensee notified NRC that Unit I may have been in an unanalyzed condition from about 7:50 p.m. to 8:24 y.m.
that date.
The Unit was operating at 90-percent power during this time.
The problem condition involved the erroneous manipulation of Unit
electrical switchgear instead of Unit 2 switchgear.
The operator assigned to de-energize breakers for Valves 2-QMO-225 and 2-QMO-226 (East and West charging pump minimum flow valves) de-energized I-QMO-225 and I-QMO-226 instead.
The error was found and corrected by the licensee's independent verification process within 35 minutes.
Without power, the subject valves could not have responded as designed to a safety injection signal.
On SIS, both valves close.
If reactor coolant system (RCS) pressure is below 2000 psig, they remain closed.
This is to ensure adequate boric acid injection.
If RCS pressure remains above 2000 psig, the valves reopen after a 5-second time delay.
While briefly de-energized, neither valve could have moved.
The subject Unit I valves were de-energized with I-QMO-225 open and the associated pump (East)
in standby, while I-QMO-226 was closed and the West pump running.
The licensee's safety evaluation in support of a possible Licensee Event Report concluded that with Valve I-QMO-226 closed, the West train remained OPERABLE throughout the event.
With the east train inoperable with I-QMO-225 open, the
T.S. Action Statement is entered.
However, since the problem was corrected within 35 minutes, well within the T.S. Action Statement, no violation of T.S. occurred.
The inspector verified the licensee's safety evaluation and held discussions with personnel assigned to evaluate cause and corrective actions and to make recommendations on prevention of recurrence.
The following were under active consideration:
i)
making the practice of calling the control room upon breaker deactivation into a mandatory requirement (it was not done in this case),
and/or; ii)
separating planned clearances involving two trains into some distinct process which would reduce or eliminate common-mode error affecting both trains.
Nhen the inspector observed the inconsistent use of Unit number and component on switchgear tags later in the inspection (see 3.e below)
he questioned whether the tags used in this case actually specified Unit and component number.
Since these tags had been routinely destroyed, the information was no longer available.
As noted below, the potential for error using current practices was discussed with plant management.
During a tour of Unit I and Unit 2 4KV switchgear rooms, the inspector noted potential weaknesses in the process for removing switchgear from service and restoring it to service.
Plant Manager Instruction PMI-2110 states
"red tags" shall contain ".
component, position, permit No.
and tag No."
However, some of the red tagged electrical equipment had tags listing only the noun name of the affected component, without specifying the Unit number or the breaker number.
The Clearance Permits listed the numerical information, but they are kept in the Shift Supervisor's office.
Thus, the requirement for component identification was being ambiguously fulfilled.
In addition, the inspector noted some discrepancies with respect to switchgear position identification.
For example, tags on some of the motor control center breakers showed positions as "racked out (open)," but the positions on the breakers are "on," "trip," "off,"
"reset," or "lock."
Although all the breakers tagged as "racked out (open)" were "off," (i.e., the "safe" position) the actual breaker position could not correspond exactly to what was stated on the tag.
Lastly, some breakers were observed to have open covers over their respective racking mechanisms.
These covers should be closed when not in use to prevent dust and debris from entering the switchgear internal These inconsistencies and a potentially related tagging error (see 3.d above)
were discussed with plant management during the inspection and at the Management Interview.
No violations, deviations, unresolved or open items were identified.
Reactor Tri s 93702 Unit 1 Tripped from 71-percent power at 4:33 p.m.
EST on January 16, 1989, due to an error in control room valving operations.
An operator who intended to valve steam from a fossil-fueled auxiliary steam'boiler to the startup air ejectors manipulated valves out of sequence by mistake.
Instead of opening the steam supply valve first, he opened-the adjacent air offtake valve.
There was an immediate loss of. condenser vacuum which resulted in turbine trip and reactor 'trip.
Plant response was nominal through the trip sequence and immediately thereafter.
Several minutes later, when operators were securing auxiliary feedwater per procedure, one of eight injection valves did not initially close on demand with flow present.
The valve was closed after its associated pump was shut off.
The licensee investigation of the valve closure problem revealed the torque settings on the four valves associated with the turbine-driven auxiliary feedwater pump (TDAFP) had intentionally been set at the lower end of the empirically-established acceptable operating range.
This was to minimize the potential for internals damage on high closing torque.
Since the TDAFP has twice the flow capability of either motor-driven pump, the flow volume through the last valve to close is substantially greater than the flow for which the torque setting was set for during valve testing.
In this event, overtorque occurred before achieving set closure due to the higher flow rate.
The licensee reset the torque switches higher in the acceptance band and tested to show closure could be achieved against full flow.
This is discussed further in Paragraph 6,
"Maintenance."
The Unit was returned to service January 17, 1989.
No violations., deviations, unresolved or open items were identified.
Radiolo ical Controls (71707 During routine tours of radiologically controlled plant facilities or areas, the inspector observed occupational radiation safety practices by the radiation protection staff and other workers.
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 area a.
The inspector continued to follow cleanup activities associated with restoring the Unit 2 turbine building to a radiologically "clean" area.
Decontamination and packaged removal activities continued to reduce the amount of contaminated materials (from the steam generator repair project) stored in temporary laydown areas in the building.
b.
When exiting Unit 2 containment after a tour on January 13, 1989, the inspector noted that his portable radiation survey meter would not respond to a check source point in the airlock exit hall.
The instrument subsequently responded properly to another check point near the radiologically controlled area entrance.
The radiation protection staff was notified and their investigation found the check source had become detached inside the housing at the airlock location, and had fallen to the bottom rear of the housing box.
The source was re-attached properly.
c.
During one auxiliary building tour on January 24, 1989, the inspector noted a substantial amount of water on the floor on the 633-foot elevation near the Unit 1 blowdown tank.
Water was dripping from the overhead (a suspected contaminated area)
and had spread across the floor through a bounded contaminated equipment storage area.
The radiation protection staff was notified.
They learned the water came from the lifting of a relief valve associated with the blowdown tank.
This water was not a source of contamination, and the area was mopped up without inadvertent spread of confined contamination from the overhead or the storage area.
No violations, deviations, unresolved or open items were identified.
6.
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:
that 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 No. 023757:
removing upper casing, inspecting rotor for rust, placing AFW pump turbine in layup, and restoration following the outage
b.
Job Order No. 016551:
replacement of turbine-driven Auxiliary Feedwater (AFW) Pump Woodward Governor with spare c ~
d.
Job Order No. 016550:
turbine-driven AFW pump trip and throttle valve preventive maintenance Job Order No. 710327:
replace Unit 2 turbine-driven AFW pump governor valve e.
Job Order No. 41121; turbine-driven AFW pump Unit 2 refueling outage preventive maintenance The inspector monitored maintenance on the Unit 2 turbine-driven AFW pump in-progress under these job orders, observed cleanliness and housekeeping in the pump room during and after work being performed, verified calibration of torque wrenches and micrometers, and reviewed the following procedures used to perform the maintenance.
- 12MHP5021.056.002,
"Maintenance Repair Procedure for Auxiliary Feed Pump Turbine"
- 12MHP5021.056.005,
"Maintenance Procedure for Adjustment of the Balancing Chamber Pressure on the Auxiliary Feed Pump Turbine Trip and Throttle Valve"
- 12MHP5021.056.007,
"Maintenance Procedure for Adjustment of Trip and Latch Mechanism of Auxiliary Feed Pump Turbine Trip and Throttle Valve"
- 12MHP5021 ~ 056.008,
"Maintenance Procedure for the Disassembly, Repair, and Reassembly of the Turbine Driven Auxiliary Feed Pump Governor Valve"
- 12MHP5021.056.009,
"Maintenance Procedure for the Disassembly, Repair, and Reassembly of the Trip and Throttle Valve on the Auxiliary Feed Pump"
- 12MHP5021.056.010,
"Turbine Driven Auxiliary Feed Pump Mechanical and Electronic Overspeed Trip Tests" During the review of **12MHP5021.056.008 for the replacement of the TDAFW pump governor valve (Job Order No. 710327)
the inspector found =it difficult to correlate measurements taken at certain steps in the procedure to the acceptance criteria listed on a separate attachment.
The procedure steps described loca.ions which were keyed to an attached drawing, but the drawing did not provide an accurate'resentation of where to take the measurements.
Further, the descriptions in the procedure steps did not match those listed on the acceptance criteria attachment.
With the assistance of a member of the maintenance department the inspector was able to determine where the measurements were to have been taken.
Some values documented were not correct.
For example, the inner diameter of the sleeve in which the valve plug travels was measured at 6.06" while
the inner diameter of the valve body bore was measured at 2.58".
The inspector examined the valve body from which these measurements were obtained, and noted that the inner diameter of the valve body bore was approximately-6".
There was no safety significance or operability impact on the TDAFW pump since a
new valve had been installed.
The measurements were taken from an old valve for information purposes.
Of concern is the difficulty in determining the correct measurement points and the lack of clarity in their descriptions.
This is considered an open item (50-316/89002-01)
pending licensee review and resolution of this matter.
f.
During an inspection of emergency diesel generator 2CD on January 4,
1989, following a significant amount of maintenance and modification activities and a 24-hour endurance run (see NRC Inspection Reports No. 315/88027(DRP);
316/88031(DRP)
the inspector noted the following:
i)
a cable distribution panel cover atop the local diesel control panel was not in place; and, ii)
one fuel line lacked a rubber grommet where it passed into the valve gear "fulcrum box" housing atop the cylinder - it had been wrapped in what appeared to be paper or cardboard instead.
It was later determined to be gasket material.
While following up on the above, the inspector learned the subject diesel had been declared
"OPERABLE" at 3:55 p.m.
on December 29, 1988, and was considered.
OPERABLE at the time of the observations.
Unit 2 Technical Specifications for plant conditions obtained at the time did not require that the diesel be OPERABLE.
Licensee administrative controls, in fact, prohibit declaring a safety-related system or component OPERABLE if unapproved parts or materials have been installed.
This prohibition is stated in Section 3.7, 1 of Procedure PHI-2290,
"Job Orders."
The same procedure requires that work performed by Job Orders must be within the scope of work indicated on the controlling Job Order form, (Section 3.8.3)
and the Job Order form must be accurately and completely filled out to provide a clear expla'nation of exactly what work was performed (Section 3.8.4).
Applicable Job Order forms neither authorized nor documented installation of the substitute grommet material.
Finally, Section 3.8.5 of PHI-2290 specifically includes replacement of cable tray and electrical box covers as required completion items.
Failure to authorize, document and control installation of an unapproved grommet material such that the 2CD diesel was declared OPERABLE with unapproved material still installed, is contrary to Procedure PHI-2290,
"Job Orders."
In that implementation of Procedure PHI-2290 is a requirement of Technical Specification 6.8. l.a by reference to Appendix "A" of Regulatory Guide 1.33 (at Section I.5), these circumstances are considered to represent a
violation of the referenced Technical Specification (Violation 316/89002-02).
As part of the inspection activities associated with the 2CD diesel generator, the inspector reviewed support documentation (primarily Job Order forms and procedures)
collected for closeout review by the maintenance engineer.
The activities were of such number and complexity (over 30 Job Orders, 9 design changes, and about two dozen inspections and tests)
that an activity flow chart had been prepared to establish sequences and track completion.
The documentation showed good planning and in-process control.
Closeout review, however, was tardy.
As of January 23, 1989, nearly a month after the diesel had first been declared operable, numerous supervisory review sign-offs, in procedures and on Technical Specification testing forms, were absent.
For example, the 18-month inspection procedure was not signed off as "Accepted" on Page 2 of the procedure, nor was the associated Technical Specification testing form signed off.
The procedure (**12MHP4030 STP.046
"EDG System 18-Month Inspection" ) documented as a "defect" (Step 7. 11.6. 1)
the missing grommet discussed in Paragraph 6.f above.
Steps 9 and 9.2 specify maintenance supervisory review to include correction of all defects and a final engine operability run.
The maintenance supervisor signed off by mistake (Step 10. 1)
on December 23, 1988, after a "final" engine run.
This resulted in the diesel being declared operable with the "defect" still present, because completion of additional verification reviews and sign-offs is not a prerequisite to operability.
The deferral of such reviews, however, meant the licensee missed opportunities (Steps 10.2 and 10.3 sign-offs were also incomplete)
to identify and correct the mistake.
Timely verification reviews could be important to mistake-free return to operability of many systems and components worked on during the Unit 2 steam generator repair outage.
This was discussed at the Management Interview.
Job Order No. 030959:
Unit 2 control room emergency lighting verification and relamping.
Job Order No. 030929:
installation of redesigned seismic support/restraint on accumulator No.
24 valve No. 2-IRV-140.
The inspector met with maintenance department representatives subsequent to the torque switch adjustments on auxiliary feedwater injection valves in followup to the failure of one valve to reclose after the Unit 1 reactor trip of January 16, 1989 (See Paragraph
above).
The final evaluation was incomplete, but the licensee committed to timely completion and a report (probably with the LER required for the reactor trip) on findings and on corrective and preventive actions.
Alternative testing methods were being specifically evaluated, since testing had established the original torque setting which proved unsatisfactory.
The inspector met with representatives of the licensee's Instrument and Controls (IKC) group on February 3, 1989 to review the preventive maintenance program development and implementation status.
The
activities had been largely "on hold" for several months (except for mandatory items - e.g.,
Technical Specification calibrations and checks) while a new program was developed to replace the (suspended)
old one.
The periodicity of the original program was arbitrary; not based on component importance or history.
Further, manpower resources were inadequate to the original goals, but data were lacking to justify which activities should be sacrificed.
The licensee representatives described and/or provided:
i)
initial Facility Database (FDB) screening to identify nearly 15,000 "instruments;"
ii)
screening and sorting criteria to develop the final "inclusion list;"
iii) methods whereby preventive maintenance frequency was assigned; iv)
short-and long-term trending techniques to validate or adjust frequency; v)
administrative controls (procedures, reports) for activity management.
The comprehensive maintenance program for instruments and controls was placed in effect January 1,
1989.
The controlling procedures had been developed or revised, but not approved and issued (both were in the final stages)
at the conclusion of the inspection.
One violation, one open item, and no deviations or unresolved items were identified.
7.
Surveillance 61726; 42700 The inspector reviewed Technical Specifications required surveillance testing as described below and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were properly accomplished, that test results conformed with Technical Specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and that deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following,activities were inspected:
a.
- 12THP 6040 PER.001:
"Centrifugal Pump Performance Tests" b.
- 2-OHP 4030 STP.017T:
"Turbine Driven Auxiliary Feedwater System Test"
- 2-OHP 4030 STP.017TV:
"Turbine Driven Auxiliary Feed Pump Trip and Throttle Valve Operability Test"
, 2-OHP 4030 STP.034:
"Local Valve Position Verification Test"
- 1THP 4030 STP.410:
"Reactor Trip SSPS Logic and Reactor Trip Breaker Train "A" Surveillance".
The inspector observed that the proper prerequisites and precautions were met and documented as required and that initial checks were carried out properly as described in the Test Procedure.
The inspector then observed part of the test of the bypass breaker and reactor trip breaker and found no problems.
- 120HP 4021.082.018:
"Racking In and Out Reactor Trip, Reactor Trip Bypass, and NG Set Output Breakers."
The inspector observed this procedure as it was used in conjunction with the SSPS Train "A" surveillance discussed above.
- 12NHP 5021.032.025:
"Emergency Diesel Engine Timing and Balancing."
The inspectors observed the portion of the procedure which provides for compression and combustion pressure adjustments.
Pressure measurements are made using a drum type pressure indicator with a recording card that is attached to each cylinder in sequence.
Pressure is then calculated using a scale provided with each indicator instrument.
All the pressures observed fell within the proper range of 1140 to 1160 psig.
- 20HP 4021.032.001:
"Starting, Paralleling, Loading, and Shutting Down the Emergency Diesel Generators."
The inspectors observed part of the loaded run on No.
CD diesel generator.
An improvement was noted over a previous run in that oil leakage was significantly reduced.
It was also evident that repairs had been accomplished on a jacket water leak and a loose pipe support on the oil crankcase blower line.
- 12NHP 4030 STP.029:
"Test of Grinnel Hydraulic Snubbers."
Licensee testing of normally inaccessible Unit 2 hydraulic.snubbers using this test procedure resulted in 28 "failures" (among some
tests)
to meet established acceptance criteria.
Each test failure was separately documented for corrective action on a Condition Report.
The "failures" were predominantly against bleed rate criteria for smaller snubbers.
The inspector discussed the situation, and the potential for a common root cause, with plant management.
They had already initiated a generic re-examination of the process, based on the recognition that the results being reported were entirely out of character with prior plant experience.
The generic re-examination showed:
i)
- the compression pressure gauge was of inappropriate scale (0-3000 psig) for small snubbers
- to which well under 1000 psig is applied - and the gauge may have been "sticking" on an incorrect reading;
ii)
the tension pressure gauge was in error by about 60 psig; iii) several "failed" snubbers showed no seal leakage upon disassembly, and; iv)
both recently rebuilt snubbers (since 1985)
and never-rebuilt snubbers (since 1976) were failing.
The licensee replaced the compression pressure gauge, recalibrated the tension pressure gauge (both had been "in calibration" ) and retested 19 "failed" snubbers.
Fifteen were found acceptable.
Several previously failed snubbers which had been readjusted to acceptable, as shown by the suspect gauges, were again pulled out of the plant and retested.
As expected from the nature of the gauge problem, all remained acceptable but set more conservatively than required.
The ".failures" will count as such in the licensee's administrative program for determining sample size, the result being a 100-percent inspection and test sample this cycle.
A new test machine, equipped with direct-reading load cells vs. pressure gauges, has been ordered.
- 12THP 4030 STP.234:
"Acoustic Valve Monitor System Test."
Four monitors are installed on the piping associated with each of the pressurizer safety and power operated relief valves.
l!hile performing the procedure, the licensee discovered that two monitors and their respective output indication appeared to be cross-wired.
Actuation of the "A" monitor gave indication that "C" monitor actuated.
The procedure was terminated at this point and a Condition Report documenting the-problem was generated by the licensee.
The acoustic monitors are not required to be functional until the plant is in hot shutdown (MODE 3).
The inspector wi 11 continue to follow this item as part of his ongoing inspection.
Before the test was suspended, the inspector noted the test technician recording an anticipated alarm that had failed to respond when expected.
In fact, the correct alarm responded (Annunciator 208, Drop 45) but the annunciator window used different terminology for the condition from that used in the procedure.
The inspector pointed the discrepancy out for reconciliation.
Further review found additional discrepancies between or among the annunciator windows in Unit 1 and the annunciator response procedures.
An information binder in the possession of the Unit 2 operators which purported to show future changes in annunciator designations also indicated disagreement with the alarm response procedure and the annunciation windows.
These additional discrepancies were pointed out for reconciliation.
The noted discrepancies did not cause any specific problem (though the potential existed to unnecessarily "fail" an acceptance criteria by failure to recognize an alarm).
They did illustrate the difficulty
of performing testing to a valid, current procedure while,changes are in progress (both hardware and procedural) for the system being tested.
k.
Test results from several infrequently performed system flow balance tests were not entirely satisfactory.
Individual Condition Reports were written to address discovery by testing of valves which did not respond to their correct "flow retention" position.
These included:
i)
2-CMO-429 (CCW from 2W RHR heat exchanger)
ii)
2-WNO-738 (ESW from 2W CCW heat exchanger)
iii) 2-WNO-734 (ESW from 2E CCW heat exchanger)
Further, Unit 1 Valves 1-WMO-725 (ESW supply to emergency diesel 1CD) and 1-FMO-232 (East motor-driven auxiliary feedwater to steam generator 13) were found by-stroke-time testing to be off their correct "flow retention" positions.
The inspector questioned whether there is a need for licensee evaluation of the overall control on "flow retention" positions.
This was discussed at the Management Interview.
Ho violations, deviations, unresolved or open items were identified.
8.
Fire Protecti on 71707)
F>re 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
~
The licensee issued Unit 1 Licensee Event Report No. 315/88014 dated January 12, 1989, to document discovery of an apparent design control deficiency which affected the fire protection safe shutdown analysis.
In brief, plant modifications in about 1985, which were intended to effect separation of safe shutdown support functions, failed to completely do so.
A control cable for Unit 1 essential service water (ESW) Train A was not rerouted out of the Unit 2 cable vault, and a control cable for Unit 2 ESW Train B was not rerouted out of the Unit 1 cable vault.
A single cable vault fire could therefore have caused loss of three of four trains of ESW.
This condition was not previously analyzed.
Should the only ESW train secure from fire damage be taken out of service, permissible by T.S.
during Unit shutdown, a fire in the operating Unit cable vault could eliminate all ESW.
This scenario was not addressed in the LER.
During this inspection, Unit 1 was in power operation while Unit 2 was in an outage.
With the Unit 2 Train B
ESW susceptible to loss from a Unit 1 fire, the inspector questioned licensee measures either
to ensure Train A was kept operable, or to secure Train B from the postulated failure mode which is caused by a spurious closure of the pump discharge valve 2-WNO-704.
The licensee acted the same day to secure Valve 2-WMO-704 from failing closed.
This action was independently verified by the inspector.
When the inspector reviewed the historical status of Unit 2 Train A, he found it had been out of service from December 12-23, 1988, for a special test.
This information and the LER were under evaluation within NRC Region III at the conclusion of the inspection.
b.
Licensee Problem Report 89-139 documents a failure to submit a
special report to NRC within 30 days of an extended period (greater than seven days) of fire barrier inoperability.
Action requirements for compensatory measures were met throughout the time the barrier was degraded, so no potential safety problem occurred.
The licensee
. submitted the specified report (three weeks late) the same day the oversight was recognized.
The inspector concluded the fai lure to comply with the timeliness requirements was identified, reported and corrected by the licensee and it lacked safety significance.
Further, a single similar late example (a year earlier)
among numerous timely reports, showed the problem is not repetitive or due to failed prior corrective action.
These are the conditions of 10 CFR Part 2 Appendix C for violations for which no NRC Notice of Violation will usually be issued, and no such Notice is being issued in this case.
One violation (not cited)
and no deviations, unresolved or open items were identified.
9.
Emer enc Pre aredness (82201 The licensee declared an Emergency Plan
"Unusual Event" at 10:00 a.m.
(EST)
on January 30, 1989, because both emergency diesel generators for Unit 2 were inoperable.
The Unit was in NODE 5.
The Train A diesel was undergoing maintenance for a sticky fuel rack on one cylinder bank when a routine sampling of the fuel oil storage tank for the Train B diesel found sediment and water in the fuel.
The Train B diesel in Unit I, which was operating at 70-percent power, uses the same fuel supply, so it was likewise declared inoperable and Unit I entered a 72-hour LCO.
The day tank for boih Units'rain B diesel, which would supply the first two to four hours fuel supply, were immediately sampled and found free of contaminants.
A small amount of contaminated fuel was pumped off the bottom of the Train B storage tank where the sample is collected.
A re-sample found the fuel to be water and sediment free.
The respective Train B diesels were declared operable and the "Unusual Event" terminated at 2:03 p.m.
A precautionary sample of the Train A storage tank showed clean fuel.
The inspector's review of event identification, classification, and reporting showed these functions had been properly performed.
No violations, deviations, unresolved or open items were identified.
10.
Outa es 42700, 60710, 61701, 71711, 92701 The NRC consultant continued the ongoing review of the licensee's plant
'startup planning and coordination to ascertain whether systems disturbed during the outage would be returned to an operable status prior to plant startup and whether plant testing, heatup, and startup would be conducted in a controlled manner and in accordance with approved procedures.
Consultant onsite inspection visits were made during the weeks of December 26, 1988 and January 2,
1989.
a
~
Prior Ins ection Concerns Inspection concerns initially identified in NRC Report No. 50-316/88031(DRP)
were subject to continuing.insp'ection during this period:
i)
Control Rod Drive Shaft Ins ection Procedures During the prior inspection, the consultant noted that draft refueling Procedure 2-OHP SP.071,
"Refueling," did not contain adequate guidance or criteria for inspection of control rod drive shafts stored in poorly maintained environmental conditions.
On December 28, 1988, the licensee provided Revision 1 of the procedure which included Attachment B, "Drive Shaft Installation Guidelines."
This attachment provided adequate inspection guidance and provided for inspections to be done by station guality Control inspectors instead of the refueling contractor as originally planned.
Inspection of the shafts in'ccordance with the above procedure found the shafts spotted with strippable
"decontamination paint" overspray and coated in varying degrees with a residual film from the dirty storage water.
Problem Report No.89-022 documented the situation.
These conditions and appropriate corrective actions were analyzed by the licensee and reviewed by NRC.
At the end of this inspection, the licensee had acceptably cleaned the shafts and reinstalled them in the reactor; ii)
H drostatic Test Retest Trackin During the primary and secondary system hydrostatic tests, several test exceptions and omissions were identified as
b.
Com discussed in Inspection Report No. 50-316/88031.
The licensee had no method for formally identifying and tracking these test discrepancies through completion.
Based on this observation, the licensee implemented a periodic departmental status memo detailing hydrostatic test exceptions requiring retest.
The continued implementation of the tracking method was reviewed during this inspection period and was found acceptable.
1 ex Surveillance Testin 61701 Surveillance Testing plans, procedures, and test data were reviewed and portions of major surveillance tests were witnessed.
Tests were reviewed to verify that, the procedures were properly approved, met applicable technical, regulatory, and administrative requirements, and were properly performed.
Tests reviewed and observed (in part)
were:
- 12THP SP.175:
"BIT Flow Coefficients," Revision 1, witnessed on January 2-3, 1989.
During performance of SP. 175, extensive gas binding and cavitation of the west centrifugal charging pump (CCP) occurred when a valve (CS-370)
in the chemical and volume control system was not tightly closed, causing entrainment of volume control tank nitrogen cover gas in the CCP suction.
The consultant observed the licensee's initial discovery and troubleshooting of the condition on January 2.
During the troubleshooting, the cognizant performance engineer and the shift crew departed substantially from the procedure in attempts to identify the source of gas binding.
Eventually, after the apparent source was found, an "Instruction and Procedure Change Sheet No. 3" was issued to formalize the new lineup.
Although
'he reactor core was removed during these system manipulations, the observed latitude in system alignment and configuration control activities indicates a need for increased discipline and rigor in these activities as plant startup approaches.
- 12THP 4030 STP.217B:
"DGCD Load Shedding and Performance."
During performance of blackout testing per STP.217B, Step 5.5, the non-essential service water (NESW)
pumps restarted when the containment spray signal was reset.
The procedure data sheets required that the pumps should not have restarted.
Problem Report No.89-010 was written on January 5,
1989 documenting the above.
Additional discussions with the Performance Department indicated that the pump logic performed in accordance with the respective schematic drawings but the licensee was unsure whether the restart circuitry was consistent with the facility accident analysis.
The problem remained under investigation at the close of this inspection and will be reviewed during the continuing NRC consultant inspection.
c.
Containment Restoration On January 4, 1989, the consultant and the resident inspector accompanied a team of licensee personnel performing inspections of containment restoration and cleanup activities in the No.
1 and
Steam Generator Cubicles.
The team included two experienced senior licensed operators and cognizant Steam Generator Replacement Project personnel.
The inspectors found that, although significant strides had been made in cleanup and restoration of the containment areas, ongoing work in these and adjacent areas and the general condition of the areas required further extensive licensee work.
Also,-the removal.
of major scaffold installations and construction material had only recently made access to some areas possible.
The scope and rigor the licensee's inspection and cleanup activities appeared appropriate with reasonable sensitivity to identifying possible hidden or indirect damage to containment equipment.
Ongoing containment cleanup activities will be reviewed during the continuing NRC consultant inspection.
No violations, deviations, unresolved or open items were identified.
11.
Safet Assessment/
ualit Verification 37701, 38702, 40704, 92720 The effectiveness of management controls, verification and oversight activities, in the conduct of jobs observed during this inspection, was evaluated.
The inspector frequently attended management and supervisory meetings involving plant status and plans and focusing on proper coordination among Departments.
The results of licensee auditing and corrective action programs were routinely monitored by attendance at Problem Assessment Group (PAG)
meetings and by review of Condition Reports, Problem Reports, Radiological Deficiency Reports, and security incident reports.
As applicable, corrective action program documents were forwarded to NRC Region III technical specialists for information and possible followup evaluation.
The inspector advised the licensee another facility (Nine Mile Point Units 1 and 2) had performed a gA surveillance on Morrison Knudson (MK) and found problems sufficient to lead to issuance of a Part
Report.
The D.C.
Cook licensee relied heavily on MK-Ferguson Company for services and supplies used on the Unit 2 steam generator repair outage, so a review was conducted to determine Cook plant implications, if any.
The licensee learned MK Company and MK-Ferguson are segregated and independent from each other, including operating under separate gA programs.
Documentation of the review establishing D.C.
Cook would not be affected by implications if the Part
Report were provided to the inspector, who noted no problems.
b.
During ongoing licensee review of the effects of errors in the vendor-supplied valve/operator weight and center-of-gravity data for small Copes-Vulcan brand valves, the licensee discovered his drawings were in error in the case of two of the valves in Unit l.
The Unit was in power operation when it was learned, by removal of insulation for visible inspection, that a two-way support was installed for Valves 1-IRV-251 and 1-IRV-252 instead of the three-way support shown in applicable drawings.
The valves are Boron Injection Tank (BIT) bypass valves.
As promised in his correspondence (AEP:NRC: 1084 dated December, 9,
1988) the licensee declared the affected components inoperable pending repair.
No Technical specification Limiting Conditions for Operation apply to these valves.
Repairs were completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
c ~
Continuing licensee review concerning a Mestinghouse Type DB-50 reactor trip breaker, serial No. 850.068-2, establi'shed this breaker was not in fact a D.C.
Cook reactor trip breaker.
As noted in NRC Inspection Reports No. 050-315/88027(DRP);
316/88031(DRP)
the licensee had committed to determining whether this breaker, considered to contain suspect welds, could be in service or in stock at D.C. Cook.
This item is considered resolved.
d.
The inspector reviewed licensee interpretations, reviewed and approved by the Plant Nuclear Safety Review Committee, involving Technical Specifications for cold overpressurization protection for the reactor pressure vessel, and relating to utilization of the containment purge system, and identified neither safety nor administrative problems.
No violations, deviations, unresolved or open items were identified.
12.
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.
(Open)
NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification."
This Bulletin, dated December 20, 1988, prescribed inspections and analyses to be performed to determine surge line movement has been properly controlled and accounted for.
Previous communications involving similar concerns included Bulletin 88-08 dated June 22, 1988, and Information Notice 88-80 dated October 7, 1988.
Prior to receipt of the subject Bulletin 88-11, the licensee had performed a detailed physical inspection of the Unit 2 surge line, considering the information of the earlier communications and discussions between the resident inspector and plant management.
The Unit 1 line has been inaccessible for such inspection, being in service.
The results of the the. Unit 2 inspection are documented in a December
internal memorandum.
All thirteen restraints were inspected and clearance measurements taken in four dimensions with ambient containment and RCS temperatures.
Additional inspections were conducted at 350 degrees/
420 psig and at 550 degrees/2320 psig.
No evidence of pipe movement,
.
sufficient even to dent or buckle insulation set flush to some restraints, was noted during these inspections.
No violations, deviations, unresolved or open items were identified.
13.
Alle ations/Review (92705, 99014 RIII-88-A-0053
On April 18, 1988, Region III received allegations from a former maintenance worker who had been employed at the Donald C.
Cook Nuclear Plant by Catalytic Industrial Maintenance Company (CINCO).
On August 10, 1988, Region III forwarded these allegations to the licensee for review and followup; the licensee's response was received by Region III on September 12, 1988.
A copy of the Region III letter and the licensee's response (after removal of all exempt information) are included as attachments to this report.
Review of the licensee's response revealed that it adequately addressed the alleger's concerns with one exception:
a CIMCO foreman was allegedly not red-lining drawings.
NRC Review To resolve this remaining concern the inspector reviewed the following procedures and instructions which provide the training, job requirements, and job responsibilities for CIMCO pipefitter supervisory and craft personnel:
Plant Mana er Instructions PNI)
PMI 2010, PMI 2220, PNI 2110, PMI 2160, PNI 2290,,
PMI 2030, PYiI 2080, PYiI 4010, PMI 5040, PNI 7020, PMI 7030, Plant Nanaget and Department Head Instructions, Procedures, and Associated Indexes System Internal Cleanliness Criteria Clearance Permit System Control of Chemical Materials and Cleaning Agents Job Orders Document Control Emergency Plan and Implementing Procedures Plant Operations Policy Design Change Control Program AEPSC Site guality Assurance Condition Reports and Plant Reporting Plant Mana er Procedures PMP PMP-6010.ALA.001, ALARA Program - Review of Plant Activities PMP-6010.ALA.004, ALARA Improvement Report System
'I
Plant Mana er Standin Orders PMSO PNS0.037, Concrete Drilling Permit PNS0.075, Opening of Possible Pressurized Lines De artment Head Procedures AHP2060.SEC.055, Protected Area Personnel Access/Exit Requirements 12MHP5080 SP.001, Craft Training 12MHP5021.001.031, Fire Barrier Penetration Seals 12NHP5021.001.033, Anchor Bolts 12NHP5021.001.063, Installation
& Fabrication of Component Supports, Hangers, and Restraints 12MHP5021.001.005, Steam Generator Manways 12MHP5021.001.064, Instrument
& Control Air Installation All procedures were specifically reviewed for instructions or requirements for "red-lining" of drawings, a practice some licensees used to identify discrepancies between an actual installation and a drawing of the engineered installation.
Particular attention was paid to those procedures and instructions involving fabrication and installation, document control, design change control, quality assurance, and condition reporting; these are all areas where instructions and requirements for red-lining could exist.
No requirement for pipefitter foremen or craft to red-line drawings was located, Instructions (PMI-7030) specify use of a Condition Report for such discrepancies.
Conclusion Based on the licensee's response and the inspector's review of the remaining concern, this allegation is unsubstantiated and is closed.
No violations, deviations, unresolved or open items were identified.
14.
0~en Items Open Items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both.
An Open Item disclosed during the inspection is discussed in Paragraph 6.c.
15.
Mana ement Meetin (30702 A management meeting was conducted at the D.C.
Cook plant site on February 2, 1989, with Nr.
E.
Greenman, Director of the NRC Region III Division of Reactor Projects, along with members of his staff; Mr. M. Alexich, Vice President
- Nuclear Operations Division (AEP),=
and Nr.
W. Smith, Jr., Plant Manager, along with members of their staff.
The meeting included a discussion of licensee self-assessment initiatives, lessons learned, an overview of the Unit 2 steam generator repair project, and other topics of mutual interest.
16.
Mana ement Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on February 9, 1989, 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.
The following items were specifically discussed:
a.
the "wrong unit" tagging error of December 24, 1988, and the potential causes, including observed lack of numerical specificity on some electrical component tags (Paragraph 3);
b.
the inconsistencies among procedure steps and attachments, including the drawing and acceptance criteria sheet, for TDAFP governor valve measurements (Open Item - Paragraph 6.e);
c.
the return of emergency diesel 2CD to OPERABLE status with an unauthorized part installed (Violation - Paragraph 6.f);
d.
the potential review and signoff process for completed maintenance, causing incomplete documentation weeks after completion of work and compromising the utility with such reviews for early problem identification (Paragraph 6.g);
e.
the difficulties encountered in acoustic monitoring system testing and the inconsistencies among the two units and associated reference materials (Paragraph 7.j);
f.
the apparent
"cluster" of five recent events involving "flow retention" valve positions being out of specification, and the desirability of assuring controls in this area are adequate (Paragraph 7,k);
9 ~
the potentially expanded implications of Unit
LER 88014 (Paragraph 8.);
h.
resolution of some issues, and continuing evaluation of others, relating to pending Unit 2 return to service (Paragraph 10);
results of review of an allegation (Paragraph 13), and; j.
the general scope and content of a February',
1989 Management Meeting (Paragraph 15).
Attachments:
1.
Ltr E.
Greenman to M. Alexich dtd 8/10/88 2.
Ltr M. Alexich to A. B. Davis dtd 9/9/88 22