IR 05000315/1985036
| ML17324A590 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 01/24/1986 |
| From: | Hehl C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17324A589 | List: |
| References | |
| 50-315-85-36, 50-316-85-36, NUDOCS 8602110201 | |
| Download: ML17324A590 (22) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/85036(DRP);
50-316/85036(DRP)
Docket Nos.
50-315; 50-316 Licenses No.
American Electric Power Service Corporation Indiana and Michigan Electric Company 1 Riverside Plaza Columbus, OH 43216 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, MI Inspection Conducted:
November 5 through December '9, 1985 Inspectors:
B.
L. Jorgensen J.
K. Heller C.
L. Wolfsen R.
L.
Hague Approved By:
C.
W. Hehl, Chief Projects Section 2A
/ zy'~<
ate Ins ection Summar Ins ection on November 5 throu h December
1985 Re orts No. 50-315/85036 DRP)
50-316 85036 DRP R
d
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d b
b
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d b
of licensee actions on previously identified items; operational safety verification; reactor trip/safety system challenge review; surveillance; maintenance; and reportable events.
In addition, an Enforcement Conference held in the offices of NRC Region III on November 13, 1985 to discuss concerns and options relating to surveillance program conduct is addressed in this inspection report.
The inspection involved a total of 195 inspector-hours by four NRC inspectors including 19 inspector-hours during off-shift.
Results:
Of the seven areas inspected, no violations or deviations were sdent)fied.
The licensee was requested to provide a written response regarding improvements to avoid unnecessary challenges to safety systems (Paragraph 4).
Programmatic weaknesses regarding adherence to Criterion VIII of Appendix B
to 10 CFR 50 were identified as a matter of concern (Paragraph 7)
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DETAILS 1.
Persons Contacted a.
Inspection:
November 5 - December 9,
1985
"M. G. Smith, Jr., Plant Manager
"B. Svensson, Assistant Plant Manager
"A. A. Blind, Assistant Plant Manager
"T. Kriesel, Technical Superintendent-,Physical Sciences J.
A11ard, Maintenance Superintendent
"K. Baker, Operations Superintendent
"J. Stietzel, equality Control Superintendent
"T. Bielman, Planning Supervisor
"L. Gibson, Technical Superintendent-Engineering
"J.
Sampson, Operations-Production Supervisor
~D. Mizner, Maintenance-Production Controller
~M. Horvath, equality Assur ance Supervisor P.
Leonard, Administrative Compliance Coordinator-gC The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
"Denotes personnel attending exit interview December 9, 1985.
b.
Enforcement Conference:
November 13, 1985 American Electric Power M.
S. White, Jr.,
Chairman of the Board and CEO, AEP J.
E. Dolan, Vice Chairman - Engineering and Construction M.
P. Alexich, Vice President - Nuclear M.
G. Smith, Jr., Plant Manager J.
G. Feinstein, Manager, Nuclear Safety and Licensing R.
F.
Kroeger, Manager, equality Assurance Several other members of the plant and corporate staffs were in attendance.
U.
S.
Nuclear Re ulator Commission J.
G. Keppler, Regional Administrator, Region III C.
E. Norelius, Director, Division of Reactor Projects N. J.
Chrissotimos, Chief, Projects Branch
S.
A. Varga, Chief, Operating Reactors Branch 2, NRR D.
L. Migginton, Licensing Project Manager, NRR C.
M. Hehl, Chief, Projects Section 2A Additional members of the NRC staff were also in attendanc I 4
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IT 2.
Licensee Actions on Previousl Identified Items'
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a.
(Open)
Open Item (315/84013-04; 316/84015-04 E.
):
The turbine driven auxslsary feedwater pump (TDAFP),sn each Unst's equipped with a non-safety-grade control air system'w'hich,had not been "fail safe" tested.
The subject air system 'failed during a reactor 'trip event of November 25, 1985 discussed in Paragraph 4.c below, the failure mode being loss of air pressure via an air line break.
The TDAFP continued to perform in this case despite the line break.
b.
C.
d.
e.
(Closed)
Unresolved Item (315/84019-01; 316/84021-01):
The leakage integrity of the respective Unit's control room cable vaults was considered questionable.
The integrity of the respective vaults has since been demonstrated acceptable as part of testing performed to support modifications to installed fire suppression systems.
(Closed) Violation (315/84022-02):
Posting of change sheets in a radiation instrument calibration procedure, in use in the plant was not in accordance with procedure change control requirements.
The licensee's corrective and preventive actions as described in his letter (AEP:NRC:0917) dated February 1, 1985 and as verified by Quality Control surveillance report QCTPS-85-0290 were considered acceptable for this item.
(Closed)
Open Item (315/84022-03; 316/84024-01):
The licensee identified a potential conflict between inservice testing (IST)
performance methods and Technical Specification requirements for maintaining pump "operability" in certain modes.
Two specific valves (common series mini-flow isolation valves in the safety injection system)
were involved.
The licensee deleted the valves in question from testing procedures for modes where the conflict was created, and changed the valve summary sheets to reflect proper test conditions for these valves.
Quality Control surveillance report QCO-85-0340 documents verification of these actions, leaving "open" the inclusion of the subject valves in cold-shutdown test procedures.
This occurred with Change Sheet No.
5 to Revision 8 to ""1 OHP 4030.STP.008 (Unit 1) dated July 1985, but the analogous procedure for Unit 2 has apparently not been changed.
This reflects an inconsistency between the proc'edures for the respective Units which appears inappropriate and which is the basis for a new "Open Item" identified in Paragraph 5.c below.
(Closed) Confirmatory Action Letter (315/85022-03; 316/85022-03):
A Confirmatory Action Letter (CAL) dated August 30, 1985 addressed licensee review of stipulated surveillance activities with respect to timeliness.
The review was completed, corrective action taken for identified discrepancies, and the licensee given authorization by Region III for MODE change based on satisfactory CAL implementation.
(Closed) Confirmatory Action Letter (315/85022-04; 316/85022-04):
The CAL referenced in e.
above also addressed assurance that no surveillance requirements are omitted.
This was also completed satisfactoril '
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g.
(Closed) Confirmatory Action Letter (315/85022-05; 316/85022-05):
The CAL above also addressed inclusion of the process sensor 'in
'alibration and response time testing activities.
This was
'erformed satisfactorily.
Items e., f. and g. led to licensee identification, during performance of agreed-upon reviews or testing, of a few items which were determined to be reportable as Licensee Event Reports pursuant to 10 CFR 50.73.
Further review of the specific findings and licensee actions relating thereto will be performed in follow up on these Licensee Event Reports.
No violations or deviations were identified.
0 erational Safet Verification Both Units operated at power during the inspection period, and both experienced operational transients (see Paragraph 4 below).
The inspector observed control room operation including manning, shift turnover, approved procedures and Limiting Condition for Operation (LCO)
adherence; and reviewed applicable logs and conducted discussions with control room operators during the inspection period.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems, and nuclear and reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
Tours of the auxiliary building, turbine building, and screenhouse were made to observe accessible equipment conditions, including fluid leaks, potential fire hazards, and control of activities in progress.
On November 9, a Unit 2 shutdown was commenced pursuant to a Technical Specification Limiting Condition for Operation (LCO) on the turbine driven auxiliary feedwater pump.
The inspector specifically verified compliance to action requirements and reporting requirements.
Mithin about three hours, the pump had been repaired and tested, and the Unit exited the LCO.
During a tour of the Unit 1 control room on November 13, 1985 the inspector observed pump discharge pressure for the safety injection pumps was reading approximately 1300 pounds.
The plant was in Mode 3 (diluting to criticality following a refueling outage) with no safety injection pumps running.
The inspector discussed this with the Unit Supervisor who informed the inspector that the pressure was trapped in the lines from the safety injection actuation of the previous day.
The safety injection actuation is discussed in Paragraph 4.b below.
The pressure was bled from the lines and the indication restored to normal prior to the end of the shift.
The inspector performed a review of the Unit 2 west Residual Heat Removal (RHR) system using licensee drawing OP-2-5143, to verify that:
correct flow path and valve positions were maintained and no condition existed
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that degraded the system.
A minor discrepancy was noted when a grating hatch was found leaning up against valve RH-122.
This was discussed with the Shift Technical Advisor, who repositioned the grating.
No violations or deviations were identified.
4.
Reactor Tri s - Safet S stem Challen e Review The following events were reviewed by the resident inspectors to determine:
the significance of the event; the performance of safety systems; immediate actions taken by the licensee; radiological consequences; and corrective actions taken.
a ~
b.
On November 4, 1985 at 4:25 p.m.,
an automatic engineered safety features actuation occurred in Unit 1 which resulted in a reactor
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trip signal.
The initiating event was an erroneous high source range neutron flux indication.caused by a personnel error while the Control and Instrumentation (C8I) Department was performing startup surveillance testing.
This event has been documented by the licensee in Licensee Event Report 315/85059, which is subject to further review.
The Unit was in Mode 3 with the reactor trip breakers open.
All systems functioned as expected.
While this event was not of great safety significance, the inspectors emphasized that errors resulting in challenges to safety systems was a concern.
The licensee's short term corrective action included counseling of the C8 I technician on the importance of correctly identifying circuitry.
I Unit I had a safety injection (SI) actuation on November 12, 1985 at 10:24 a.m.,
due to an indicated high steam flow coincident with actual lo-lo average reactor coolant temperature.
Testing of steam generator instrumentation for 1-THP 4030 STP.022
and 4 Mismatch Protection Set II" required the associated bistables to be in the trip condition, causing the indicated high steam flow.
Concurrently, testing of the auxiliary feedwater system flow retention circuits resulted in a cooldown of the reactor coolant system to the lo-lo average temperature setpoint, causing the safety injection (SI) and steam line isolation.
All systems functioned as designed in response to the SI, with an estimated 1500 gallons of concentrated boric acid being injected by the centrifugal charging pumps.
This event reflects a weakness concerning licensee control of concurrent testing activities to avoid unnecessary challenges to safety systems and Technical Specification requirement non-conserva-tisms; i.e., safety injection resulted in the Boron Injection Tank (BIT) and North Boric Acid Storage Tank (N'AST) boron concentrations falling below Technical Specification requirements.
Further review is anticipated in followup to the expected Licensee Event Report on this ite I V
C.
d.
On November 25, 1985 at 10:43 a.m.,
an indicated 2 of 4 "high negative flux rate" trip signal resulted in a Unit 1 trip from 78K power.
Procedure 1 THP 6030 IMP. 131, which checks the time constant on the rate trip circuit for excore nuclear power instrument N-41, was in progress requiring all bistables for N-41 to be tripped.
This surveillance activity results in a computer alarm "NIS tilt" and "N-41 channel in test" requiring manual quadrant Power Tilt calculations to be performed.
For this purpose, an instrument was being used to "read" the other excore channels.
When the probe was removed from channel 44, the channel spiked, making up the 2 out of 4 logic.
All plant systems responded normally except a non-safety control air line to the Turbine Driven Auxiliary Feedwater Pump (TDAFP), which failed, causing the pump to go to its preset design speed, and removing speed control from the control room operators.
The TDAFP was subsequently isolated by closure of'he steam supply valves, since both motor driven pumps were running.
An Open Item exists for each Unit (315/84013-04 and 316/84015-04)
addressing the fail safe testing of the non-safety grade control air system of the TDAFP as described in Paragraph 2.a above; neither item has been closed out.
The licensee has replaced the copper tubing with flexible stainless steel tubing on Unit 1 and plans to make the same modification on Unit 2 during the February 1986 outage.
Unit 2 tripped from about 81K power due to a steam flow vs.
feedwater flow mismatch coincident with low water level for steam generator No.
22 at 2:58 p.m.
on November 13, 1985.
The trip signal was the result of removing the No.
22 steam generator pressure transmitter MPP 221 from service for maintenance on the root valve.
The bistables for this pressure transmitter were placed in the tripped condition for the repair without apparent recognition of the fact that feedwater flow control was selected to receive its signal off the same channel.
Indicated steam flow decreased, causing a
commensurate actual feedwater flow decrease, which resulted in an actual low (29X) steam generator level.
Plant operators took manual control of the associated feedwater regulating valve, increasing flow again to an indicated mismatch condition and yielding a temporary level "shrink" which reached the 26K reactor trip setpoint for flow mismatch conditions.
All systems responded as designed for the trip, and the Unit was returned to service the following day.
The licensee documented this event in Licensee Event Report 316/85037, and committed to revising the maintenance procedure prior to its next use and briefing the operators on the changes made.
This event is considered a consequence of operator error and inadequate procedural direction, with respect to transferring control channels prior to tripping potentially associated bistables.
The above events suggest a need for improvement in authorization and control of activities to avoid unnecessary challenges to safety systems.
This was discussed at the Management Interview, and the licensee is requested to address this concern in a written respons No violations or deviations were identified.
5.
Survei 1 lance
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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.
a.
Performance of all or parts of the following tests was observed:
- "12 THP 6030 IMP.002 Analog Rod Position Indication Calibration
"~12 THP 6030 IMP.038
"~1 THP 4030 STP. 004 ARPI Coi 1 Stack Voltage Data Overtemperature and Overpower Protection Set I b.
The inspector reviewed the completed surveillance procedures for:
"%12 MHP 4030 STP.003
""12 MHP 4030 STP.004 Maintenance Procedure for Inspection of Steam Generator Hydraulic Shock and Sway Suppressors.
(Performed April 17, 1985 for Unit 1 steam generator snubbers.)
Inspection of ITT Grinnell Hydraulic Shock and Sway Suppressors.
(Performed August 15, 1983 and May 2, 1985 for Unit 1 "inaccessible" snubbers.)
(Performed June ll, 1984 and September 3,
1985 for Unit 1
"accessible" snubbers.)
As shown by the performance dates, the licensee has categorized the snubbers into two groups (accessible and inaccessible during reactor operation).
While reviewing the completed data the inspector found that snubber 46 (located in the containment on the main steam line between steam generators 1 and 4) was incorrectly classified as an
"accessible" snubber in the Technical Specifications (Table 3.7-4)
and attachment 2 to ""12 MHP 4030 STP.004.
This was pointed out to licensee personnel.
The licensee was correctly testing this snubber with the "inaccessible" group, technically contrary to Technical Specifications and his procedure.
The licensee was reminded that in this case it was his responsibility to revise the Technical
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Specification.
The licensee is processing a change to the Technical Specifications and the affected procedure."
Yj Mhile reviewing the surveillance performed May 2, 1985 the inspector determined that the oil reservoir for snubbers 12 and 44 had been found empty.," The snubbers were removed, function'ally tested; satisfactor'ily and rebuilt prior'to'e'use.
"The., surveillance
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documented that no functional failures were found and scheduled the next visual inspection normally; i.e. not accelerated".
The licensee had shown via functional testing that the snubbers were operable however, Technical Specification 4.7.8.b states
"...when the fluid port of the snubber is found to be uncovered, the snubber shall be determined inoperable and cannot be determined OPERABLE via functional testing for the purpose of establishing the next visual inspection."
Since the reservoirs for snubbers 12 and 44 were empty and by the above definition inoperable, the licensee was required to increase the visual inspection frequency for inaccessible snubbers from 18 months
+25K to 6 months
+25K (reference Technical Specification 4.7.8.a).
This meant the next inspection frequency began November 30, 1985 (May 2, 1985 plus 6 months)
and ends January 25, 1986 (May 2, 1985 plus 6 months plus 25K).
This was discussed with the Maintenance Superintendent on December 5, 1985.
He concurred with the inspector's views and immediately scheduled the required test, which was completed with all satisfactory results by December 9, 1985.
These results permit placing this group of snubbers on a 12 month visual inspection frequency.
The inspector reviewed surveillance test procedures 1-OHP 4030 STP. 016, Revision 8, "Reactor Coolant-System Leak Test",
and the analogous
OHP 4030 STP.016, Revision 3, for implementation of Technical Specifications.
It was noted that 1 OHP 4030 STP.016 for Unit 1 had a procedure change made and Plant Manager approval on September 25, 1985.
Procedure
OHP 4030 STP.016 for Unit 2 did not have the same change implemented as of November 1985.
The change to the Unit 1 procedure appeared applicable to Unit 2.
A similar discrepancy between analogous procedures was noted in Paragraph 2.d above.
The inspector discussed the review of procedure ch'anges that could affect both units with Operations, Technical, and guality Assurance personnel.
There appears to be no controlled method to guarantee common changes affecting both units will be implemented for each unit.
Developing a method to ensure procedure changes made to one unit are reviewed and implemented, if applicable, for the other unit will be tracked as an Open Item.
(Open Item 315/85036-01; 316/85036-01).
On November 23, 1985, Licensee Condition Report 12-,11-85-2381 reported that during the scheduled biannual review problems with two power range Nuclear Instrument (NI) calibration procedures,
~~1 THP 6030 IMP.131 and ~"2 THP 6030 IMP.231 were identified.
These calibration procedures allowed a value of 2+0. 1 seconds for the power range positive and negative rate trips time constant; however, the Technical Specification allowable value is >2 second ~ ~
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The actual values allowed had the potential for exceeding the Technical Specification values in the nonconservative direction.
Following this determination the licensee conducted surveillance testing and demonstrated acceptable performance and initiated procedure changes to alleviate the identified concern.
Concerns about another performance criterion in these procedures were identified on October 2, 1985, when the licensee determined that power range neutron flux high positive and high negative rate trip setpoints were set at nonconservative values with respect to the values specified in Technical Specifications (Table 2.2-1, items 3 and 4).
Information provided by Westinghouse Technical Bulletin No. NSID-TB-85-13, "Flux Rate Trip Setpoint",
had led the licensee to an analysis of plant procedures which revealed his interpretation of a Westinghouse
"Precautions, Limitations, and Setpoints" document was incor rect.
The licensee concluded that this event did not represent an unreviewed safety question as defined in 10 CFR 50.59, and has now incorporated the correct setpoints into the procedures.
No violations or deviations were identified.
6.
Maintenance Station maintenance activities of safety related systems and components listed below were observed and/or reviewed to ascertain that they 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; and activities were accomplished using approved procedures.
The following maintenance activities were observed or reviewed:
JO (Job Order) 43759 Trouble shooting of Unit 2 field temperature recorder
GN 12.
JO 031825 JO 94802 and associated supple-mental Job Order Repair of Unit 1 pipe support No.
52.
Remove and reinstall Unit 1 steam generator snubbers 82, 81 and 80.
JO 93544 Inspection of Unit 1 steam generator snubber No.
JO 88973 Remove, replace, test and install Unit.1 snubber No. 14.
~JO 82704 Perform 18 month surveillance (visual)
inspection of "accessible" Grinnell snubbe "JO 82703 Perform 18 month surveillance (visual)
inspection of "inaccessible" Grinnell snubber.
~Discussion of findings associated with these activities is contained in Paragraph 5.b above, since the observations were more closely related to the surveillance function.
No violations or deviations were identified.
Re ortable Events Through direct observation, discussions with licensee personnel, and review of records, the following Licensee Event Reports (LERs) were reviewed.
The review addressed compliance to reporting requirements and, as applicable, accomplishment of immediate corrective action.
If indicated "closed", the review showed appropriate corrective action to prevent recurrence had been accomplished in accordance with applicable requirements.
Unit 1 (Open)
LER 315/85048:
The LER concerns incorrect replacement parts installed on the turbine driven auxiliary feedwater pumps (one each Unit).
Mhile complete details concerning this finding are not yet available, the finding itself contributes to ongoing NRC concern that the licensee has not been exercising adequate control over replacement parts for safety related systems.
Two examples of installation of wrong type check valves in December 1983 and April 1984 were addressed in previous reports.
Inspection Report No. 315/85026(DRS);
316/85026(DRS) identified a violation concerning the corrective action process for these items.
The violation focused on an apparent failure to disposition the corrective action documents (Condition Reports No. 12-12-83-1342 and No. 2-04-84-493)
in a way which addressed interim measures to preclude recurrence until implementation of final corrective action.
The licensee is required to address this corrective action deficiency in response to the identi'fied violation.
Subsequently, NRC learned of the use of incorrect replacement parts in the cases covered by the subject LER (several occurrences dating back to about 1977)
and in at least two additional cases.
First, when the two Unit 1 station batteries were replaced in June and July 1985, and the two new batteries which were procured for this purpose were slightly different from each other, some cable specifically sized for each new battery was instead installed on the other.
Second, modifications in support of the electrical equipment environmental qualification program (both units)
during the period of approximately June through September 1985 were performed in a number of cases with installation of an incorrect cable splicing kit.
These two cases, identified by the licensee, did not result in the compromise of safety-related equipment at a time it was required to be operable.
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These examples are indicative of programmatic weaknesses regarding the adherence to Criterion VIII of Appendix B to 10 CFR Part 50 (i.e.
identification and control of materials)
which are in need of management attention.
This is a matter of concern to the NRC and will be reviewed further in future inspections.
Unit 2 (Open)
LER 316/85014:
An inadvertent safety injection signal was generated during the installation of a Design Change.
AEOD review of this LER resulted in a memorandum dated October 30, 1985 from F.
Hebdon (NRC-AEOD) to E. Schweibinz (NRC RIII) requesting additional information.
The Plant Manager was provided a copy of the correspondence and is currently preparing a revision to the LER.
No violations or deviations were identified.
Mana ement Meetin
- Enforcement Conference An Enforcement Conference was held on November 13,'985 at the NRC Region III office.
The purpose of the'onference was to discuss Region III concerns relating to implementation of surveillance requirements, as identified in Inspection Reports 315/85027(DRS);
315/85028; 316/85028 and 315/85029(DRP);
'316/85029(DRP).
The violations identified in these reports are currently being evaluated by the NRC for escalated enforcement action.
Attendance at the meeting is described in Paragraph 1.b above.
~0en 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 5.c.
Mana ement Interview The inspector met with licensee representatives (denoted in Paragraph l.a above) following completion of the inspection on December 9, 1985.
The inspector summarized the scope and findings of the inspection as described in these Details.
The following were specifically discussed:
a.
The inspector expressed concern that the challenges to reactor safety systems reviewed during this inspection generally appeared avoidable, and indicated these unnecessary challenges reflected a
need for greater control of concurrent activities and improved attention to details (Paragraph 4).
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b.
C.
Surveillance frequency requirements for Unit 1 "snubbers" as a
function of visual inspection findings, were discussed.
The inspector noted only the Unit 1 program had been reviewed and suggested 'the licensee assure himself by review of Unit 2 practices that no error in inspection frequency had been made there (Paragraph 5. b).
The inspector expressed concern that separate procedures accomplishing the same thing in the respective Units are not positively controlled to assure an appropriate degree of uniformity.
This was identified as an Open Item (Paragraph 5.c).,
d.
The programmatic weaknesses regarding adherence to Criterion VIII of Appendix B to 10 CFR Part 50 were specifically described by the inspector (Paragraph 7).
The inspector also discussed the likely informational content of the report with respect to documents or processes reviewed.
The licensee was afforded the opportunity to identify any such documents/processes which might be proprietary, and none were so designated.
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