IR 05000315/1989021
| ML17328A098 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 08/01/1989 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17328A096 | List: |
| References | |
| 50-315-89-21, 50-316-89-21, IEB-88-003, IEB-88-004, IEB-88-3, IEB-88-4, IEB-89-001, IEB-89-1, NUDOCS 8908110153 | |
| Download: ML17328A098 (24) | |
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION III
Repot t Nos.
50-315/89021(DRP);
50-316/89021(DRP)
Docket Nos. 50-315; 50-316 License Nos.
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, MI Inspection Conducted:
June 7 through July 18, 1989 Inspectors:
B.
L. Jorgensen D.
G.
Passehl Approved By:
.
L.
rgess Chief Projects Section 2A DA r/flat'ns ection Summar Ins ection on June 7 throu h Jul
1989 (Re ort Nos.
50-315/89021(DRP).
0-316 89021 ORP I
I I
p I
I Id I
p of: actions on previously identified items; plant operations; ESF actuations; radiological control s; maintenance; surveillance; emer gency preparedness;
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reportable events; Bulletins, Notices and Generic Letters; and NRC Region III requests.
A special NRR evaluation of an emergency diesel overspeed event (a previously identified item followup), and a Management Meeting in NRC Region III on June 22, 1989, were also conducted.
No Safety Issues Management System (SIMS) items were reviewed.
Results:
Of the ten areas inspected, no violations or deviations were
>dent>fied in nine areas.
One violation was identified (Level IV - operation with an out-ot-specification reactor trip channel - Paragraph 9) in the remaining area.
The inspection disclosed weaknesses in completing maintenance effectively, both from the perspective that some jobs required hardware rework, and due
",.o evidences of incomplete ancillary processes (post-job cleanup and testing, reviews and signoffs) which left maintenance effectiveness in question.
No new Open Items and/or Unresolved Items were identified.
8908ii015 89080l PDR ADOCVi 050003i5 O
DETAILS 1.
Persons Contacted
"W. Smith, Jr., Plant Manager
"A. Blind, Assistant Plant Manager - Administration J.
Rutkowski, Assistant Plant Manager - Production
"L. Gibson, Assistant Plant Manager - Technical Support
"B. Svensson, Licensing Activity Coordinator
"K. Baker, Operations Superintendent J.
Sampson, Safety and Assessment Superintendent E. Morse, gC/NDE General Supervisor
"T. Beilman, I8C Department Superintendent J. Droste, Maintenance Superintendent T. Postlewait, Technical Superintendent
- Engineering L. Matthias, Administrative Superintendent
"J. Wojcik, Technical Superintendent
- Physical Sciences
"K. Alexejun, equality Assurance Auditor D.
Loope, Radiation Protection Supervisor
"J.
Kauffman, Construction Manager
"M. Barfelz, Safety/Assessment Senior Engineer 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 July 21, 1989.
2.
Actions on Previousl Identified Items (92701, 92702)
a o An evaluation has been made by the vendor (Westinghouse)
of two solid state protection system (SSPS)
safeguards driver cards, as part of the root cause determination associated with a Unit One reactor trip on November 23, 1988 (LER 315/88013).
The reactor trip was caused by a spurious underfrequency signal condition originating from one of the two SSPS driver cards.
There were no culpable failure conditions found in the evaluation; Westinghouse blamed the spurious signal on transient surface contamination of one of the two SSPS driver cards.
b.
The inspector followed up questions identified in a previous Inspection Report (No. 50-315/89014(DRP);
50-316/89014(DRP)
concerning an April 1, 1989 motor-driven auxiliary feedwater pump (MDAFP) run.
First, two procedures covering MOAFP operation and standby readiness each check flow control valves closed before pump start, but the valves were open for the subject run.
The operators explained that they were aware of the normal procedures, but chose to throttle (about one turn) the flow control valves open to ensure a flowpath
in case of emergency leakoff (ELO) path failure.
After two pump trips, the flow control valves were found about 50-percent open, providing too little flow resistance.
Because the ELO path was now known to be clear, the third (successful)
start was made with the flow control valves closed.
A Standing Order (OS0.019) provides a limit of two consecutive start attempts, but the subject run involved three consecutive attempts.
Followup established neither of the first two attempts involved the motor being energized more than five seconds.
Therefore, motor winding overheating did not occur and, in fact, the Standing Order itself exempts such start attempts.
Finally, it was not clear whether a "flow retention" feature associated with the flow control valves (to limit excess flow to a faulted steam generator)
was energized and working properly.
This will remain undetermined.
The retention feature was not considered or required operable for the subject pump run, and design changes were in progress on the valve controls.
The capability of this feature to prevent pump starting overcurrent in simulated accident conditions is separately verified in Technical Specification surveillance testing.
During this inspection period, NRC completed its evaluation of an overspeed event on the Unit 1 CD diesel generator which occurred on April 10, 1989. This included a site visit by a technical expert from the Office of Nuclear Reactor Regulation (NRR).
A meeting was held at the D.
C.
Cook Plant on June 16, 1989, to discuss whether or not 1CD emergency diesel generator (EDG) could be considered OPERABLE.
The licensee's position was that the root cause of the April 10 overspeed event was:
1) poor fuel linkage adjustment, and 2) individual cylinder adjustments which, in combination, resulted in the engine receiving more fuel than necessary to maintain synchronous speed (514 rpm) at no load.
As a consequence, the diesel engine oversped before it was manually tripped.
The NRR staff had previously accepted the concept of this root cause evaluation, but had requested quantitative data to support it. The licensee conducted a test in May, 1989, which produced one data point.
The licensee believed this data point supported their root cause determination.
The staff did not believe this single datum served as proof of the root cause hypothesis.
At issue was the claimed large increase in engine speed noted after a very small increase in fuel.
The staff believed that the characteristic frictional horsepower curve for this type of engine precluded such a
substantial speed increase from so little additional fuel.
After a period of discussion, it was decided to conduct additional testing to obtain specific, quantitative data.
The tests involved locating a dial indicator on the governor actuator arm, reducing engine speed to a stable condition around 450 rpm with the governor
load limiter, and monitoring engine response and actuator arm movement while increasing fuel to one cylinder.
Two tests of this type were conducted.
In addition, data was obtained on fuel rack positions for various engine speeds between 350 rpm and synchronous speed.
In the NRR staff's view at the time, the tests were inconclusive.
In addition, the staff noted some governor anomalies.
The licensee did not concur, but agreed to replace the governor.
Subsequently, following further consideration of some of the observations made during the June 16 tests, but primarily due to independent collection, review and analysis of germane diesel performance data, the staff revised its position.
Based on this independent evaluation, the NRR staff concluded that the 1CD diesel could be considered OPERABLE. This revised staff position was communicated to the licensee on June 19, 1989.
The licensee confirmed plans to change out the governor following receipt of a replacement, on a schedule which minimizes the negative impact on the plant.
The governor will be returned to the vendor for inspection and any necessary repairs, and NRC will be informed.
No violations, deviations, unresolved or open items were identified.
3.
0 erational Safet Verification (71707, 71710, 42700)
Routine facility operating activities were observed as conducted in the plant and from the main control rooms.
Plant startup, steady power cooperation, 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 eq'uipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift/duty turnover, and the degree of professionalism of control room activities.
Evaluation, corrective action, and response for off normal conditions or events, if any,,
were examined.
This included compliance to any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, equipment condition, and tagout logs were conducted.
Proper return to service of selected components was verified.
Unit 1 completed a refueling, maintenance, modification and testing outage during the inspection period, with initial synchronization to the grid at 4:44 a.m.
on July 4, 1989.
During preparations to return the unit to commercial service following turbine testing on July 5, the licensee discovered two check valves on which post-maintenance testing had not been performed (see also Paragraphs 6, "Maintenance" and 8,
) and the unit was returned to MODE 5
b.
C.
to complete the tests.
The Unit was subsequently restarted July 8 and operated normally for the remainder of the inspection.
Unit 2 was out of service for a voluntary maintenance outage of about two weeks duration, ending June 24, 1989.
During the outage, reactor coolant system leak sources were identified and selectively repaired.
Following the June 24 restart, the unit operated normally for the remainder of the inspection period.
Amendment No.
126 to the Unit 1 Facility Operating License No.
DPR-58, dated June 8, 1989, authorized unit operation at reduced primary coolant system temperature and pressure conditions.
This is intended to reduce the potential for steam generator U-tube stress corrosion.
Operating procedure and instrument/control system setting revisions developed in anticipation of the altered operating conditions were observed by the inspector through power escalation and routine operation.
These preparations proved effective in minimizing the amount of "fine tuning" necessary to return to full power operations.
d.
,On June 20, with Unit 1 operating in NODE 4, and both motor driven auxiliary feedwater pumps in service, a control operator observed motor amps at 30 amps and 38 amps on the East and West pumps e.
respectively.
The West pump was secured, and amps increased on the East pump.
A review of recent surveillance test results showed both pumps performed satisfactorily, but the West pump had higher discharge pressure.
The two pumps share an emergency leakoff line, such that a concern.arose over the adeq'uacy of East pump leakoff (mini-flow) with both pumps in service.
This has similarities to the condition of concern identified in NRC Bulletin 88-04, on which NRC follow up is incomplete (see Paragraph 10).
Among the items inspected during containment tours were the moveable incore detector system seal table area, and the airlock door seals.
(1)
The Unit 2 seal table area was clean and dry, with only seven of 58 fittings showing any traces of boric acid, indicative of leakage.
All indications were very slight.
(2)
The door seals exhibited a slight coating of silicone grease, along with various small paint, dirt and otherwise unidentifiable chips of foreign material (see also Paragraph 7. e).
No violations, deviations, unresolved or open items were identified.
4.
ESF Actuations (93702)
a.
On June 11, 1989, Unit 1 reactor coolant pump No.
13 was started with indicated primary coolant system pressure at about 350 psig.
Pressure increased momentarily to about 370 psig, and valve NRV-153 (a pressurizer power-operated relief valve aligned for system low temperature overpressure protection)
opened and relieved pressure
back to about 355 psig.
It then reclosed.
Operation of this protective feature, while not a defined
"ESF actuation,"
required a
special report pursuant to Technical Specification 3.4.9.3 Action C, with which the licensee complied by virtue of their letter dated June 26, 1989.
b.
On June 17, 1989 a Unit 2 reactor trip signal was generated during instrument testing which caused the reactor trip breakers to open.
The unit was in MODE 4 at the time.
The instrument group had been performing a series of instrument checks using a procedure which identified that trip signals would result.
The reactor trip breakers were open during this initial testing.
When a bistable associated with intermediate range nuclear instrument channel (N-35) was found out of calibration, the oncomi.ng shift instrument technician was directed to do the applicable calibration procedure.
This second procedure would not normally cause trip signals to occur, so it was authorized by the operators.
In this instance, however, trip signals were inherent in the setup remaining from the previous test.
Meanwhile, the operators had started a third test themselves, for which it was necessary to close the reactor trip breakers.
It was this condition that set the stage for the trip signal opening the breakers.
System response to the trip signal was normal.
Further inspection review, is planned in follow up to the anticipated LER.
No violations, deviations, unresolved or open items were identified.
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5.
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 areas.
b.
Inspector tours in the containment buildings included verification of proper controls for "extreme high" radiation areas.
Unique locking provided for the hatch to the pit under the reactor vessel, pursuant to corrective actions derived in response to NRC concerns in this area, was physically inspected and verified (reference Inspection Report No.
50-315/89017(DRSS);
50-316/89016(DRSS)).
Occasionally, items were identified on inspector tours which were referred to responsible personnel in the radiation protection group for review and appropriate corrective action.
For example:
1)
A bag of what appeared to be contaminated trash was observed adjacent to the airlock test equipment storage are )
What appeared to be a bag of contaminated trash was lying atop cable ducting near the freight elevator on the 633-foot elevation.
Neither of these locations is designated for a laydown area.
3)
A two-step steel stair assembly was hung by a chain from a small (approximate one-inch) waste system pipe (MD-709-L2) in the dirty radwaste holdup tank transfer pump room.
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: the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures; and post maintenance testing was performed as applicable.
The following activities were inspected:
a 0 Inspector followup to an event involving the erection of scaffolding in the 1CD diesel room while the diesel was OPERABLE (and 1AB diesel was not) revealed the root cause was a verbal miscommunication among licensee and contractor supervisors and the work crew.
The scaffolding tags were issued in advance, with a note to defer scaffold er ection in the 1CD room until 1AB was "cleared" and 1CD declared inoperable.
Subsequently, verbal instructions involving staging of materials and the imminence of 1CD being declared inoperable were misunderstood as authorization to begin work.
Future scaffold erection in safety related areas will be released for physical work to start only on written authorization.
This satisfied the inspector.
b.
Job Order JO 703791:
repair cracked weld on No.
22 reactor coolant pump bearing oil lift pump support shelf.
The apparent weld crack was observed by an NRC inspector on a containment tour in about October, 1988 (reference Inspection Report No. 50-315/88026(DRS))
and the subject Job Order was written October 21, 1988.
A reinspection by the resident inspector on June 14, 1989, with the unit shut down after an 85-day run, found that the crack had not been repaired; neither had it grown worse.
Maintenance department records and the assigned scheduler were consulted to determine the history on the Job Order.
The review disclosed a miscommunication
had occurred and the scheduling group thought no welding was needed (they believed only the paint was cracked)
before the March 1989 startup.
Subsequently, lack of documentation to show even the painting work complete placed the job in a "hold open" status.
The weld repair was finally reported complete on June 17, 1989, prior to Unit 2 restart.
A tour of the Unit 2 west main steam isolation valve enclosure showed maintenance was complete to reinstall insulation and clean up the work area.
Incomplete work and associated clutter in the area were noted in a previous (Report No. 316/89018(DRP))
inspection report.
The inspector noted the licensee was identifying additional examples (e.g.
Condition Report 1-06-89-1202) of failure to maintain cleanliness or failure to restore cleanliness after maintenance.
This was discussed with management at the Management Interview.
Decontamination Contract:
cleaning of Unit 2 containment lower ventilation (CLV) units 1 and 4.
Inadequate heat transfer from the four Unit 2 CLV units was causing elevated containment air temperatures (still within limits) with Lake Michigan cooling water at only around 60 degrees Fahrenheit.
Inspection showed both the air side (tube fins) and the water side (inside the horizontal tubes)
were variously impacted with "crud."
High pressure water sprays were effective in cleaning the outside, and water lancing the inside, of the tube assemblies.
Increasing air temperatures were a
factor in the decision to shut down Unit 2 on June 10, 1989, for maintenance and inspection.
Job Order JO B004685:
check torques, and retorque as necessary, body-to-bonnet studs on safety injection loop check valves 2-SI-158-Ll through -L4.
The valves required retorquing, because all four had been torqued as though they had A-193 Grade 88 (carbon steel)
studs, but these "old" studs were replaced (per design change RFC 12-2718) last year.
The "new" studs are A-453 Grade 660 (stainless steel) studs, which should have been torqued to 952-1270 lb-ft. versus the 700-730 lb-feet actually used.
Valve 2-SI-158-Ll had developed a body-to-bonnet leak, which evidenced itself as increasing "unidentified" reactor coolant system leakage and contributed to the decision to shut down Unit 2 as noted above.
Problem Report 89-765 documented the torquing error for root cause review and corrective action.
As noted in Paragraph 3.a "Operational Safety Verification" above, the licensee was preparing to restart Unit 1 on July 5, 1989, when they discovered that two check valves had not been post-maintenance tested as required.
The stipulated testing was Type C local leakrate testing, performed to demonstrate compliance to Technical Specifications associated with primary containment integrity.
Immediate licensee actions are discussed further in Paragraph
Upon identification of the first untested valve (1-CS-442-2; reactor coolant pump seal injection line inboard check valve) the licensee's
various plant'departments, on instructions from the Plant Manager, commenced a review of all Job Orders performed during the recently-completed unit refueling outage, to ascertain whether there were additional problems.
This review identified the second untested valve (1-CTS-131-W; west containment spray header inboard check valve) several hours later.
The following day, July 6, NRC Region III requested the licensee to document his commitment to perform a verification before plant restart, of all Technical Specification and safety related Job Orders, to assure required testing was complete.
Notification of NRC Region III of the results of this verification was also requested.
The licensee complied by committing to both requests in his letter of that same date, signed by the Plant Manager.
A review of the results of the two examples of unperformed testing is included in Paragraphs 7.f and 7. g below.
Further review is planned on receipt of the anticipated Licensee Event Report (LER).
g.
While reviewing job order packages for closeout per item f. above, the plant found that a safety related valve had been welded with no specific instruction to do so, as defined in the "scope of work" section.
The valve (1-MS-325) is a one-inch globe valve, installed as the main steam to auxiliary feed pump turbine, condensate drain shutoff valve.
(The piping diagram also erroneously showed it as a
gate valve.)
The original work envisioned was minor preventive maintenance (clean/inspect; repack),
but upon disassembly the backseat was apparently found steam cut. It was subsequently welded without specific authorization, and required quality documentation and nondestructive examination were lacking.
This weld was ground out, and the valve was rewelded, examined, and documented prior to Mode 3 entry.
The items described in e, f, and g above, together with other events apparently involving ineffectively performed or administered maintenance, were the subject of a telephone conference call on July 7, 1989, among the NRC Branch Chief, the Plant Manager, and members of their respective staffs.
The NRC staff voiced concern about the relative frequency of rework or reexamination to assure the quality of maintenance.
The Plant Manager noted that the same concern had already been identified during Problem Assessment Group reviews onsite and several of the events of interest had been specifically designated for review under the Human Performance Evaluation System (HPES) to determine causal factors and contribute to preventive action decisionmaking.
This area bears continued watching by the licensee and NRC. It was identified as a weak area in discussion at the Management Interview.
No violations, deviations, unresolved or open items were identified.
7.
Survei 1 1 ance (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 accompl'ished, 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 0 b.
C.
d.
e.
""2 THP 4030 STP. 149
"Containment Pressure Protection Set IV Surveillance (Monthly)"
"~12 THP 6030 IMP.002
"Analog Rod Position Indicator Calibration."
This test was limited to calibration of a new coil stack for Unit 2 control rod H-14, which had experienced a failure on its original coil stack.
""12 THP 6030 IMP.012
"Radiation Monitoring System Calibration, Air-Liquid-Gas."
The inspector reviewed the procedure and observed the calibration check of the steam generator blowdown liquid process monitor, R-19.
""2 OHP 4030.019F
"Steam Generator Stop Valve Operability Test" The inspector followed up identification via this test procedure that two of four Unit 2 main steam isolation valves had stroked slowly (compared to ISI acceptance criteria) on June ll, 1989, only about ten weeks after the last satisfactory stroke testing.
Condition Reports 2-, 06-89-1116 and -1117 documented the problem with valves 2-MRV-210 and 2-MRV-230, respectively.
In each instance, water accumulation in the operating system dump-valve or line was suspected.
A second test of each valve (after water was vented?)
resulted in acceptable stroke times.
Licensee evaluation of the root cause and determination of appropriate corrective and preventive actions were incomplete at the end of this inspection period.
This matter will'e reviewed further as the licensee s
evaluation progresses.
Containment airlock door seals experienced continuing instances of dirt, paint chips, etc.,
becoming impinged on the sealing surface (see Paragraph 3.e).
On at least one occasion, the presence of foreign material caused gaps in the inner door seal and a hissing noise was noted by personnel exiting the Unit 2 containment.
The problem was corrected immediately (the seal was tested for containment integrity verification) and documented on Problem Report 89-0850.
Management at the Problem Assessment Group (PAG) meeting directed a generic review be made in the vicinity of the airlocks to identify and, if possible, eliminate any sources of such foreign materials.
"~12 THP 4030 STP.23F:
"Containment Spray Check Valve and Residual Heat Removal Check Valve Leak Rate Test".
This surveillance was performed because of a prior oversight to do the test at the appropriate time (see paragraph 6.f).
The inspector found no technical problems with the procedure or the results.
A change
sheet was issued, however, reducing the duration of the test from four hours to two.
The "Reason" stated for the change was that "a two hour duration will be more conservative...the shorter duration would generate a higher amount of differential pressure across the valve for the test..."
Plant Manager Instruction (PMI) 2010 (Section 3.13.3B) restricts changes of this type "...to instances where the change(s)
are needed to continue work or testing,"
and stipulates (Section 3. 13. 3G) that the reason shall be documented and based on circumstances and need.
In this case, the "Reason" for the change was a perceived need to accelerate testing prerequisite to p;
I 1i d
dhi i 1j if'nstead.
The inspector considered the justification valid, in this case.
g.
"~l THP 4030 STP.203:
"Surveillance Test Type B&C Leak Rate Test".
The subject surveillance was performed because of a prior oversight to do the test at the appropriate time (see paragraph 6.f).
The work performed and the results appeared satisfactory, but some minor inconsistencies were noted.
The first is, that the job order (No.
Apl4773) was prepared under the assumption the test would be performed in MODE 2.
The test was actually performed with the unit in MODE 5.
Secondly, as a consequence, the Appendix J valve lineup sheet and the lineup as shown on the test sketch as depicted in the above procedure did not match.
These two inconsistencies did not affect the outcome of the test, but are mentioned to note the desirability of accuracy and traceability.
No violations, deviations, unresolved or open items were identified.
8.
Emer enc Pre aredness (82201, 82203)
a 0 A Unit 2 "Unusual Event" was declared for concurrent inoperability of both emergency diesel generators on July 3, 1989.
At the time the Unit was in full power operation The first diesel (2AB) was declared inoperable when an auxiliary equipment operator on a routine room tour noted that the fuel racks were in an abnormal position.
This was traced to failure of the throttle control cylinder, a device which isolates fuel feed upon diesel shutdown (the engine had been tested a few hours earlier)
and keeps fuel isolated for a two-minute interval (except for auto-start signals)
to prevent inadvertent restarts.
Pursuant to Technical Specifications, the opposite diesel (2CD) was tested.
It started within time limits, idled properly, and carried the "test bank" load, but could not be paralleled to its bus to demonstrate bus breaker operability due to a problem with the synchronizing circuit.
In addition, some exhaust fumes were apparently being drawn back into the room through the ventilation system, so the licensee chose to shut down the engine, leave it in automatic, and declare it administratively inoperable for inability to complete testing.
Both diesels were subsequently restored and verified OPERABLE within time limits of Technical Specification A failed GE type HFA relay (see also Paragraph 10.a)
was located as the cause of the 2AB diesel problem.
The relay was replaced, the engine was successfully tested and declared operable, and the
"Unusual Event" was terminated approximately two hours after declaration.
b.
No A blown fuse was found in the primary side of the 2CD diesel output potential transformer.
The fuse was replaced, the engine (and synchronization circuit) were tested satisfactorily, and 2CD diesel was declared operable following 2AB.
Classification of the event and completion of required notifications appeared to meet all applicable requirements.
A Unit 1 "Unusual Event" was declared on July 5, 1989, based on commencement of a Unit shutdown pursuant to Technical Specification 3.0.3.
The shutdown was required because two check valves specified for containment integrity verification via Type C (local leak rate)
testing, had not been tested as required following valve maintenance.
No ACTION statement addresses discovery of such conditions with the Unit above 200-degrees Fahrenheit, so Specification 3.0.3 applied.
See also Paragraphs 3.a and 6.f.
Classification of this event, and completion of required notifications, once again appeared to meet all applicable requirements.
violations, deviations, unresolved or open items were identified.
9.
Re ortable Events(92700, 92720)
The inspector reviewed the following Licensee Event Reports (LERs) by means of direct observation, discussions with licensee personnel, and review of records.
The review addressed compliance to reporting requirements and, as applicable, that immediate corrective action and appropriate action to prevent recurrence had been accomplished.
(Closed)
Licensee Event Report LER 316/86031:
ESF (Safety Injection)
pump motor returned to service after maintenance by non-gA vendor.
The licensee's letter (AEP:NRC:0775AP) of July 14, 1989, reported on completion of the environmental testing of the subject pump motor.
This was the only remaining action for this event.
The concern involved potential radiation induced failures.
The radiation testing showed no indication of degradation or damage.
b.
(Withdrawn) Licensee Event Report LER 315/89005:
inoperable containment isolation valve for component cooling water system.
Valve testing disclosed that valve 1-CCM-458 would not close in response to a test conducted during an outage.
The failure was reported as a potential loss of containment isolation capability during previous periods of plant operation.
Further evaluation established that this valve does not affect containment integrity (it isolates only to conserve flow), and that the failure probably occurred during the testing which identified the problem.
The valve had not been moved since a successful test during a previous outage.
The basis for reporting having been determined not to apply, this LER was withdrawn by licensee letter dated June 9, 1989.
(Open)
Licensee Event Report LER 316/89010:
"Plant Operating Outside LCO Due To Inability to Determine RCS Loop Delta-T (and required Channel Calibration Values) Prior to Entry into Applicable Node".
The LER is 'summarized as follows:
On May 24, 1989 it was observed by the control room operators that the Loop 2 Delta-T reactor power indication was approximately 4 percent lower than the remaining loops.
The deviation was not limited to indication alone, but found to exist throughout the Loop 2 instrumentation channel, including input to the overpower (O.P
~ )
and overtemperature (O.T.) Delta-T reactor trip circuits.
The O.P.
and O.T. Delta-T circuitry functions to define a region of permissible reactor operation in terms of power, pressure, flow, axial power distribution, and coolant temperatures, and to trip the reactor when the limits of this region are approached.
In this case, the deviation, caused by a difference in actual and calibrated instrument values, resulted in approximately a 4 percent deviation between the maximum and nominal trip values for the Loop 2 overpower and overtemperature Delta-T reactor trip channels.
The Technical Specifications (T.S.) limit the maximum deviation to 2.6 percent for the overpower Delta-T function and to 3.3 percent for the overtemperature Delta-T function.
The deviation was apparently due primarily to the replacement of Unit 2 steam generators, which caused a change in flow distribution among the Reactor Coolant System loops.
The resulting change in Delta-T could not be measured until the unit reached full power.
The overpower and overtemperature Delta-T trips are required, however, to be operable in Modes 1 and 2.
These measurements were taken (and the deviation noted)
when the unit achieved 100 percent power on March 31, 1989, but the reportability of the deviation was not discovered until review on Nay 24, 1989.
The channel was declared inoperable and placed in "trip" on the latter date.
Corrective actions included calibration of the Loop 2 Delta-T instrumentation channel to the new value of Delta-T reactor power.
Correct operation of the overpower and overtemperature Delta-T reactor trip bistables was also verified.
Because the Delta-T value could change over time due to steam generator tube plugging, reactor coolant pump flow changes, or other changes in plant parameters, the plant will measure the Delta-T at the beginning of each cycle and adjust the calibration as necessar Technical Specifications requiring the channel trip setpoints to be within stated ranges from their calculated setpoints were not met in the time period from March 31 until May 24, 1989, for Overtemperature and Overpower Delta-T channel 2.
The further requirement that an inoperable channel be placed in the trip condition within one hour, in order that power operation proceed, was likewise not met.
These circumstances are considered to represent a violation of the noted Technical Specification requirements (Violation 316/89021-01).
One violation, and no deviations, unresolved or open items were identified.
10.
NRC Com liance Bulletins (92703)
a ~
(Open)
"Inadequate Latch Engagement in HFA Type Latching Relays Manufactured by General Electric." The fai lure of a GE Type HFA relay which rendered an emergency diesel generator inoperable on July 3, 1989 (ref.
Paragraph 8.a above)
needs to be reviewed against the concerns of the subject Bulletin.
NRC follow up was incomplete at the conclusion of this inspection.
The licensee had determined, however, that the involved relay was not a latching-type.
Consideration of this event in completing the inspection will be ensured by appropriate'inspector notation in the Bulletin inspection file.
This was discussed at the Management Interview.
b.
C.
(Open)
NRC Bulletin 88-04, "Potential Safety Related Pump Loss."
A problem (Condition Report No. 12-06-89-1171) identified during concurrent operation of both Unit 1 motor driven auxiliary feedwater pumps on June 20, 1989, needs to be reviewed against the concerns of the subject Bulletin (see also Paragraph 3.d above).
The licensee's Bulletin responses of March 3 and July 8, 1988, did not address auxiliary feedwater.
The licensee pointed out the subject system is not designed such that an auto-start against a "dead head" can occur, unlike the situation of concern in the Bulletin.
The Bulletin inspection file will be annotated and followed up as for item a.,
above.
This was also discussed at the Management Interview.
(Open)
NRC Bulletin 89-01, "Failure of Westinghouse Steam Generator Tube Mechanical Plugs."
The licensee responded to the subject Bulletin by letter (AEP:NRC: 1096) dated June 20, 1989.
The letter identified that plugs from heat No.
NN 4523 are installed in Unit 1 and, per WCAP-12244 methodology, have a remaining calculated lifetime of 353 effective full-power days (EFPD).
This is less than the previously reported (Inspection Report No. 50-315/89018(DRP);
50-316/89018(DRP))
preliminary estimate of 500 EFPD and less than the estimated remaining core cycle of 428 EFPD.
Remedial actions are being planned for implementation at the end of the cycle, during the next Unit 1 refueling outage.
This is currently scheduled for late 1990.
No violations, deviations, unresolved or open items were identified.
Unit 1 Test Results Evaluation ao CILRT Data Evaluation The inspector reviewed the data submitted by the licensee of the Unit 1 CILRT performed in June 1989.
The initial Type A test had a
duration of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at 26.6 psia.
Data was collected every
minutes.
The inspector evaluated the data using mass point time formulas and a data collection frequency of 10 minutes to verify the licensee's calculations of the leak rate and instrument performance.
The results were as follows (units are in weight percent per day)
Measurement Leak rate measured during CILRT (Lam)
Licensee 0. 118
~Ins ector 0.109 Lam at upper 95K Confidence level 0. 121 0. 118 b.
Appendix J acceptance criteria at 95K UCL: <0.75 La= <0. 1875 weight percent per day.
Su lemental Test Data Evaluation Following the satisfactory completion of the Type A test a leakage rate of approximately 3.69 scfm, equivalent to 0.241 at X 1 day was induced based on measurements taken with a mass flow meter.
Data was collected'very 5 minutes.
The inspector evaluated the data submitted with the following results (units are in weight percent per day):
Measurement Measured leakage rate, Lc, during supplemental test Licensee 0. 204 Inspector 0. 204 Induced leakage rate, Lo Lc - (Lo+Lam)
0. 241-0 ~ 155 0. 241-0. 146 Appendix J acceptance criteria: -0.0625
< [Lc-(Lo+Lam)j < +0.0625 After approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> the licensee terminated the unsuccessful verification test.
A second unsuccessful attempt was conducted for 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> using a higher induced leakage of 6.4 scfm, equivalent to 0.418 wt%%u'/day as determined by the mass flow meter.
As the test was failing the licensee decided to check the mass flow meter against a
rotometer.
The latter showed the mass flowmeter was incorrectly reading too high.
Based on the rotameter readings the original
verification induced flow rate should have been 2.03 scfm and the second induced flow rate 3.5 scfm.
Second CILRT Data Evaluation By the time the problems with the mass flowmeter were discovered the containment originally measured Lam was changing due to a leaking upper airlock inner door.
The licensee decided to pressurize the upper airlock to 10 psig and performed a new 9 hour1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> Type A test using BN-TOP-l, Rev.l formulas (total time) with the following results (units are in weight percent per day):
Measurement Leak rate measured during second CILRT (Lam)
Lam at upper 95K confidence level Licensee 0. 033 0. 111
~Ine ector 0. 033 0. 110 Appendix J acceptance criteria at 95K UCL: <0.75 La= <0.1875 weight percent per day.
Short Duration T e
A Test Su lemental Test Data Evaluation Following completion of the second Type A test the licensee induced a leakage rate of 3.5 scfm, equivalent to 0.227 wtX/day, as determined by the use of a calibrated rotameter.
Data was again collected every 5 minutes for 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
The inspector evaluated the data with the following results (units are in weight percent per day)
Measurement Measured leakage rate, Lc, during supplemental test Licensee 0.252
~Ins ector 0.252 Induced leakage rate, Lo Lc-(Lo+Lam)
0. 227-0.008 0. 227-0.008 Appendix J acceptance criteria: -0.0625
< [Lc-(Lo+L'am)] < + 0.0625 CILRT Valve Lineu or Re air Penalties Due to valve configurations which deviated from the ideal penetration valve lineup requirements for the CILRT, the results of local leak rate tests for such penetrations must be added as a
penalty to Lam at the 95K UCL to determine the "as left" leakage rate of the containment.
In addition, any improvements in leakage
rate due to penetration/valve repairs or adjustments must also be added to determine the "as found" condition of the containment.
The inspector will verify both conditions to be satisfactory as soon as the licensee submits the required data in'heir "Reactor Containment Building Integrated Leak Rate Test" report due in approximately 3 months after the completion of the test.
No violations or deviations were identified.
12.
Re ion III Re uests (92705)
A survey entitled "guestionnaire Regarding Plant Technical Specifications,"
which focused on emergency diesel generator protection circuitry and associated Technical Specification provisions, was received in the NRC resident inspector s onsite office on June 14, 1989, via facsimile transmission.
The questionnaire was forwarded to the licensee for review and response, and was completed, returned and transmitted back to NRC Region III the same day.
No violations, deviations, unresolved or open items were identified.
13.
Mana ement Meetin (30702)
A management meeting was conducted at the U.S. Nuclear Regulatory Commission (NRC) Region III office on June 22, 1989, with Dr.
C. Paperiello, Deputy Region III Administrator, and other members of the Region III staff.
Representing D.C.
Cook were Mr.
M. Alexich, Vice President - Nuclear.Operations Division (AEP), and Mr.
M. Smith, Jr.,
Plant Manager, along with members of their staff.
The meeting included a
discussion of activities related to fitness for duty, emergency planning, outage management, guality Teams, information management/long range planning, RCS leakrate and other miscellaneous items.
14.
Mana ement Interview (30703)
The inspectors met with licensee representatives (denoted in Paragraph 1)
on July 21, 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:
Increased examples were being noted in corrective action documentation which involved not maintaining or restoring work area cleanliness (Paragraph 6.c);
b.
Apparent weaknesses recently noted in the effectiveness of maintenance implementation and administration (Paragraphs 6.e, 6.f and G.g);
Preventive actions to preclude water accumulation in MSIV operating system valving or lines (Paragraph 7.d);
d.
The circumstances surrounding the declaration of "Unusual Events" in each Unit (Paragraph 8);
e.
The violation associated with inaccurate trip system setpoints for overtemperature and overpower Delta-T channels (Paragraph 9); and, f.
The need to review operational events involving the auxiliary feedwater system and an emergency diesel generator against the concerns of NRC Bulletins 88-03 and 88-04, respectively (Paragraph 10).
18