IR 05000315/1991025
| ML17329A326 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 12/06/1991 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17329A325 | List: |
| References | |
| 50-315-91-25, 50-316-91-25, NUDOCS 9112160088 | |
| Download: ML17329A326 (17) | |
Text
U. S.
NUCLEAR REGULATORY COYiYiISSION
REGION III
Report Nos.
50-315/91025(DRP);
50-316/91025(DRP)
Docket Nos. 50-315; 50-316 Licensee:
Indiana Michigan Power Company 1 Riverside.Plaza Columbus, OH 43216 License Nos.
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C.
Cook Site, Bridgman, HI,'nspection Conducted:
October'16, 1991, through November 26, 1991 Inspectors:
J.
A. Isom T.
G. Colburn D.
G. Passehl E.
R. Schweibinz J.
F. Harold C.
N. Orsini
~k Approved By:
. L. Jorgensen, Chief Reactor Projects Section 2A Ins ection Summar DAT Ins ection from October
throu h November
1991 (Re ort Nos.
50-315/91025 DRP '0-316 9102 DRP reas ns ecte
outsne unannounce inspection by the resident inspectors o
p ant operations; reactor trip; maintenance and surveillance; engineering and technical support; actions on previously identified items; and NRC Bulletins.
Results:
Of the six areas inspected, no violations or deviations were ide~ti7ied in any areas.
The inspection revealed no notable strengths this report period.
The inspection noted a weakness in the licensee's preventive maintenance of Solid State Protection System test cards in the storeroom.
Plant 0 erations:
Unit 1 operated routinely throughout the inspection period at approximately 100 percent power.
Early in November 1991 the plant Chemistry Section noted a
very small increase in the primary to secondary leak rate, through a very small increase in tritium concentration in the secondary plant.
Prior to the
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discovery, the licensee had been calculating a leak rate of arourd 0.002 to 0.003 gpm based on tritum concentration.
The leak was most recently calculated to be about 0.006 gpm.
Unit 2 operated routinely at approximately 100 percent power throughout most of the inspection period.
However, there was one reactor trip, without complications, on November 15, 1991.
liaintenance and Surveillance:
The inspector's review found activities in this area were generally performed satisfactori ly.
The licensee began replacing pneumatic components on the Emergency Diesel Generators (EDGs)
as a preventive measure following several incomplete starts during surveillance testing throughout the past year.
The work on the first scheduled EDG was observed and was satisfactorily completed with a minor weakness noted in interdepartmental communications and prejob planning.
The inspector reviewed the October 8, 1991,, Unit 2 Unusual Event and plant shutdown.
The licensee discovered a problem with the Solid State Protection System (SSPS)
during routine surveillance testing.
A weakness was noted in the licensee's control of spare SSPS cards in the storeroom.
The licensee's plant winterization activities were reviewed and the inspector noted the licensee did a good job of winterizing the plant.
En ineerin and Technical Su ort:
The inspector performed a complete walkdown of the Unit 2 Safety Injection System and.noted one minor print error.
All valves wer'e noted to be clearly and correctly labelled.
Instrument calibration due dates were checked on randomly selected instruments and all were satisfactor DETAILS 1.
Persons Contacted
'a ~
Mana ement Meetin
- November
1991 American Electric Power/Indiana Michi an Power b.
D.
H. Williams, Jr., Senior Executive Vice President, AEPSC E.
E. Fitzpatrick, Vice President, Nuclear Operations, AEPSC A. A. Blind, Plant Manager W.
G. Smith, Chief Nuclear Engineer S. J.
Brewer, Manager, Nuclear Safety and Licensing, AEPSC M.
W. Ev'arts, Manager-Nuclear Maintenance Support, AEPSC J.
B. Kingseed, Assistant Section Manager-4'uclear Support, AEPSC P.
A. Barrett, Director, guality Assurance, AEPSC J.
E. Rutkowski, Assistant Plant Manager-Technical Support L. S. Gibson, Assistant Plant Manager-Projects K. E. Baker, Assistant Plant Manager-Production B. A. Svensson, Executive Staff Assistant-P.
F. Carteaux, Safety and Assessment Superintendent T. P.
Bei lman, Maintenance Superintendent G. A. Weber, Technical Superintendent-Engineering T.
K. Postlewait, Design Changes Superintendent R. T. Rickman, Outage Manager-IEM Cook Plant M. E. Barfelz, Senior Engineer-Safety
& Assessment
= B.
P. Lauzau, Senior Engineer, Nuclear Safety 8 Licensing, AEPSC D. J.
Wi llemin, Skills Training Supervisor Nuclear Re ulator Commission (NRC)
S C. J. Paperiello, Deputy Regional Administrator, RIII W. L. Forney, Deputy Director, Division of Reactor Projects, RIII W. D. Shafer, Chief, Reactor Projects Branch 2, RIII B. L. Jorgensen, Chief, Projects Section 2A, RIII T.
G. Colburn, Licensing Pro'ject Manager, NRR W. 0. Long, Licensing Project Manager, NRR E.
R. Schweibinz, Senior Project Engineer, RIII J.
A. Isom, Senior Resident Inspector, RIII D.
G. Passehl, Resident Inspector, RIII J.
F. Harold, Reactor Intern Engineer C.
N. Orsini, Reactor Intern Engineer Ins ection - October 16 throu h November
1991
- A..A.
- J E
L. S.
- K. R.
- B. A.
- J.
R.
P.
F.
- T P
Blind', Plant Manager Rutkowski, Assistant Plant Manag'er-Technical Support Gibson, Assistant Plant Manager-Projects Baker, Assistant Plant Manager-Production Svensson, Executive Staff Assistant Sampson, Operations Superintendent Carteaux, Safety and Assessment Superintendent Bei lman, Maintenance Superintendent
G..A. Weber, Technical Superintendent-Engineering
- T. K. Postlewait, Design Changes Superintendent L. J. Matthias, Administrative Superintendent J.
T. Wojcik, Technical Superintendent-Physical Sciences M. L. Horvath, guality Assurance Supervisor D. C.,Loope, Radiation Protection Super visor The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, maintenance, and technical personnel.
- Denotes some of the personnel attending the Management Interview on December 3, 1991.
2.
Plant 0 erations (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 lineup were observed.
The performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of auxiliary equipment operators was observed and evaluated including procedure use and adherence, records and logs, communications, shift turnover, and the degree of professionalism of control room activities.
The Plant Manager,
,Assistant Plant Manager-Production, and the Operations Superintendent were well-informed on the overall status of the plant.
Evaluation, corrective action, and response to off-normal conditions or events, were examined.
This included compliance with any reporting requirements.
Observations of the control room monitors, indicators, and recorders were made to verify the operability of emergency systems, radiation monitoring systems and nuclear reactor protection systems, as applicable.
Reviews of surveillance, and equipment condition were conducted.
Unit 1 operated routinely at approximately 100 percent power throughout the inspection period except as required for routine main turbine control valve testing.
On November 6, 1991, the plant Chemistry Section noted an increase in the activity in the'secondary system, specifically in tritium concentration, corresponding to an increase in the primary to secondary leak rate.
The most current leak rate measured 0.006 gpm, which is far below the 0.347 gpm allowed by the Technical Specifications.
The Chemistry Section has increased secondary sampling frequency to once every eight hours for tritium and once per day for xenon to more closely monitor the leak rate.
Operations Department personnel are more closely monitoring the recorded steam jet air ejector offgas radiation monitor output to spot any step changes or other unexpected increases.
The inspector reviewed the procedure entitled,
"Steam Generator Primary to
Secondary Leak Detection,"
THP 6020 LAB.122, Rev.',
October 17,
'1988, and noted the procedure contains conservative guidance on unit shutdown requirements and increased sampling frequency requirements at various leak rate magnitudes.
b., Unit 2 operated routinely at approximately 100 percent power throughout most of the inspection period, except as required for main turbine control valve testing and recovery from one reactor trip.
At ll:13 a.m.
(EST)
on November 15, 1991, the unit tripped from l00 percent power due to low-low'water level in the No.
21 steam
.
generator (see paragraph 3).
The trip occurred when an isolation valve in the governor control oil circuit leaked.
The resultant control.oil pressure decrease caused all four main turbine control valves to close.
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During the subsequent forced outage, the licensee completed repairs to the moisture separator reheaters (MSRs).
The MSRs had been removed from service since early November 1991 to refurbish some valves and to replace some lengths of pipe from the second pass reheater drains.
The pipe replacement occurred as a result of the licensee's erosion and corrosion monitoring. program.
Additionally, the gas space valves for the No. 1'accumulator were refurbished.
The main turbine control valves were repaired and adjusted; Following the licensee's satisfactory resolution of the cause of the reactor trip, on November 20, 1991, the unit was'eturned to YiODE I and the main generator was paralleled.
During the power ascension,
~ the licensee repaired an emergent tube leak on a low pressure feedwater heater (no. 4B).
The licensee had held reactor power to 58 percent during the repair, then resumed power ascension to 64 percent after determining proper temperature and flow limitations with only one of the two strings of feedwater heating in service.
The unit reached 100 percent power on November 23, 1991, after the licensee was able to complete the tube leak repair and return the
"B" string of feedwater heating to service.
The inspector reviewed an event that occurred on August 20, 1991, when the licensee was filling and venting the Unit 2 reactor coolant system (RCS).
Reactor coolant Loop 4 cold Ieg temperature (Lp4 Tc)
decreased to about 95 degrees F., which is below the minimum value of 100 degrees F. for pressurizer power operated relief valve (PORV)
operability.
The event was reviewed to determine whether RCS pressure or temperature parameters at any time were in violation of the Technical Specifications (T/S).
The inspector concluded that the T/S were not violated and that RCS pressure and temperature limits were not exceeded.
The licensee performed a good investigation of the event and found the cause of this event to be inattention to detail by the operating shifts.
The Reactor Operator recording RCS temperature did not ensure, by observing the loop temperature recorders, that the most conservative ( lowest)
loop temperature was being recorded.
Loop 2
was already being'isplayed on the control board and was the loop temperature indication recorded.
= No comparison was made to the other loops to identify a difference in loop temperature.
Also, the licensee's investigation found that the Unit Supervisor did not conduct an adequate prejob brief prior to starting the fill and vent evolution.
A decrease in temperature was expected in the loops being injected to by charging, but the reactor operator was not instructed to be ready for this and no plan of action was in place in case the lower administrative limit of 120 degrees F.
was violated.
The inspector found that 'there was no procedure requirement for the operator to record the most conservative loop temperature.
The fi11 and vent procedure only stated, at step 4..5, that the "appropriate" temperature and pressure values be recorded.
The inspector learned from discussions with licensee management that a procedure change would be incorporated to the fill and vent procedure to caution operators to use the lowest loop te'mperature indication during RCS fill and vent operations.
The inspector's review of Technical Specification 3.4.9.3 (Overpressure Protection Systems)
found that throughout this event, The Limiting Condition for Operation had been met since two PORVs were open which established an appropriate vent path of the RCS.
However, the two PORVs were not "blocked" open.
The inspector found that it was acceptable to use two PORYs, open but not "blocked" open, to meet the RCS vent requirement of Technical Specification 3.4.9.3 and thus satisfy the LCO, provided the associated T/S surveillance requirement was met.
The surveillance required that the vent path be verified open at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The inspector reviewed the valve lineup sheets for the fill and vent (F8V) procedure and noted two PORVs were open and verified open by licensee personnel about six hours earlier.
Also, at the time the low temperature condition was discovered, the Shift Technical Advisor-observed the PORVs to be open.
Finally, the Operators were using the open PORVs as the RCS vent path and knew by observing other RCS parameters (such as pressure)
that the PORVs were open throughout the FKV sequence.
At the time of the event, the licensee was preparing to start up Unit 2 following the reactor trip that occurred on August 1, 1991 (ref.
NRC Inspection Report 50-315/91017(DRP);
50-316/91017 (DRP)).
Filling of the Unit 2 RCS had commenced in.accordance with the Fill and Vent (FSV) procedure, "Filling and Venting the Reacto~
Coolant System,"
- 02-OHP 4021.002.001, Rev.
10, December 28, 1991.
The Residual Heat Removal (RHR) system was aligned to loops 2 and 3 cold legs.
Charging flow to the RCS was aligned to loops I and 4.
RCS temperature prior to commencing fi11 and vent activities was approximately 125 degrees F.
Loop 2 cold leg temperature (Lp2 Tc)
was being displayed on the control room P250 computer digital.
display and was used to record RCS temperature in the FSV procedure.
About three hours into the Fill and Vent procedure, the extra Unit Supervisor (Normal shift complement includes a Unit Supervisor for'ach unit plus one additional Unit Supervisor to assist either
unit) was checking the control boards and noticed that loop I cold leg (Lpl Tc) and Lp4 Tc on the wide range temperature recorders were approximately 100 degrees F.
He was also noticed that Lp4 Tc indicated the lowest temperature of the four loops.
It had fallen slightly below 100 degrees F.
Loop 2 cold leg (Lp2 Tc) and loop 3 cold leg (Lp3 Tc) temperatures were just above 120 degrees F.
After discussion of the problem with the Shift Supervisor, Assistant Shift Supervis'or, and Unit Supervisor, Operators shifted RHR flow to Loops I and 4 in an attempt to raise the temperature in these'oops.
This was unsuccessful as temperatures in L'oops 1 and 4 remained below 120 degrees F.
Operators were then directed to terminate the RCS fill sequence.
Approximately 20 minutes later, RCS temperature in all loops had increased to above 120 degrees F.
No violations, deviations, unresolved or open items were identified.
3.
Reactor Tri (93702)
On November 15, 1991, Unit 2 tripped as a result of a low-low water level in the No.
21 Steam Generator.
The low-low level resulted from the shrink effect that occurred after all the main turbine intercept and control valves closed.
All four control valve's c'losed due to governor control oil fluid that leaked past a closed valve (2-LPI-15-Vl) in the governor control oil circuit when the licensee attempted to install a
pressure test instrument.
The leak decreased governor control fluid:
pressure causing all, four control valves to close.
The reactor trip was without complication, all systems responded as expected, and offsite electrical power remained available throughout the event.
The pressure test instrument was installed because the licensee had been experiencing turbine control valve problems during weekly turbine control valve testing.
To investigate the problem the licensee chose to check the accuracy of a pressure instrument-(2-LPI-15-VI) in the control circuit.
The licensee's intent was to isolate the instrument line and install the pressure test instrument.
After isolating the instrument line the technician removed the test plug and observed more control oil than usual dripping from the test connection.
The technician attempted to reinstall the test plug in the line.
Before the plug could be reinstalled the pressure in the line dropped causing closure of the control valves.
The licensee believed that the isolation valve leaked oil for one of two reasons.
First, the threads on the stem of the valve were stripped causing a false indication of valve closure.
Second, the metal shavings from the valve stem were introduced into the valve seat area causing a
false indication of valve closure when the disk came to rest against the metal shavings instead of its seat.
The inspectors will follow the licensee's root cause investigation as it progresses and document the results in the LER followup.
Ho violations, deviations, unresolved or open items were i'dentifie ~
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4.
t1aintenance/Sur vei.1 lance (62703 61726 71714 42700)
Corrective and preventive maintenance activities in the plant'were routinely insp'ected.
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 inspector reviewed Technical Specifications required surveillance testing as described below and verified that testing was performed in accordance with adequate procedures, 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 ~
The inspector reviewed the licensee's actions to replace the pressure regulating valves (PRVs)
and pilot operated valves (POVs) in the Emergency Diesel Generators (EDGs).
Several incomplete starts of the EDGs occurred during surveillance testing throughout the past year that brought reliability of the EDGs into question.
The licensee traced the cause of the incomplete starts to degradation of the pneumatic controls, which,included the PRVs and POVs.
The inspector obser'ved the PRV and POV valve replacements on 2AB EDG, which was the first of the four EDGs scheduled for the PRV and POV preventive maintenance.
The inspector reviewed the work to ensure that removal and restoration of the 2AB EDG were properly accomplished, which included adherence to the Technical Specifications.
Use of qualified replacement parts was verified.
The inspector saw that, except for some minor interdepartmental communication and prejob planning concerns, 2AB EDG was satisfactorily returned to service with qualified replacement parts within the time limits allowed by the Technical Specifications.
On October 23-24, 1991, the licensee performed the scheduled replacement of the PRVs and POYs on 2AB EDG.
The Instrument and Electrical ( ISE) technicians who performed the work appeared to do a
good job of installing the replacement valves.
However, the EDG was originally scheduled to be removed from service for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />; the machine was actually INOPERABLE for about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
One planning problem was that the holes drilled in the support plates to mount the new POV-I and POV-2 to the EDG were not aligned with the pre-drilled holes in the POVs.
New holes had to be drilled
into new plates.to properly mount the POVs.
This was satisfactorily done, but it was done during the 'time the EDG was in 'the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> T/S Limiting Condition for Operation (LCO) instead of before the LCO was entered.
Also, when all work was completed and the EDG was ready for post-maintenance testing, the Operation's Department did not have the required working copy surveillance procedure revision (they did have the proper controlled copy) in the control room.
The required procedure was
"AB Diesel Generator Operability Test,"
- 2-OHP 4030.STP.027AB, Rev.5, September 14, 1990.
The proper revision was eventually found.
The job also extended into shift turnover time, which delayed completion of the job as planned.
Finally, the inspector questioned the explicitness of the post-maintenance testing (PNT) requirements.
The Project Engineering staff who specified the PHT requirements stated only that the POVs and PRVs "operate" properly for the acceptance criteria, presumably through satisfactory performance of the Operation's Department surveillance test.
It was not adequately explained what exactly wa's needed to test both POY-I and POV-2, since they actuate separate air start valves on the EDG. The problem was that Operation's Department was required by their surveillance procedure, this particular month, to start the EDG on one air bank only.
This would actuate only one of the two POVs, and both POVs needed to be tested.
After reviewing the situation the licensee decided to run the full scheduled surveillance using the one air bank.
The licensee then ran another partial surveillance to "roll" the EDG with both air banks to check proper actuation of the air start valves, including both POVs.
The air starting components were verified to function properly.
The inspector reviewed the surveillance test done in accordance with the procedure titled "AB Diesel Generator Operability Test (Train B)," **2 OHP 4030 STP.027AB, Rev. 5, September 14, 1990.
The EDG was satisfactorily started, loaded, shut down, and placed in standby, using one air start valve and one POV.
It was then rolled on starting air with both air banks aligned to verify proper actuation of both POVs.
The inspector reviewed the licensee's investigation of a problem with the Solid State Protection System (SSPS) that resulted in declaration of an Unusual Event.
On October 8, 1991, during performance of "Reactor Trip SSPS Logic and Reactor Trip Breaker Train A Surveillance (monthly), "**THP4030 STP.510, Rev. 2., April 4, 1986, the licensee's Instrument and Electrical (ISE) personnel found that they were unable to obtain-good test results from some logic test circuits.
The Technical Specification'T/S)
allowed a
two hour time limit to complete the surveillance test.
This expired prior to successful resolution of the problem, and the licensee began the T/S required six hour controlled shutdown and declared the Unusual Event.
Shortly after the shutdown began the licensee
successfully performed manual logic" circuit testing and the Unusual Event and plant shutdown were terminated (See NRC Inspection Report 50-315/91022(DRP);
50-316/91022(DRP) ).
The event was.reviewed to determine if the l.icensee performed an adequate analysis of the event and implemented appropriate corrective and preventive actions.
The inspector determined that the licensee's event analysis was adequate.
The cause of the event was found to be failure of the "original" semiautomatic tester card which was in the SSPS cabinet when the problem first developed.
The licensee's troubleshooting during the event was hampered because several
"bad" logic test cards, assumed
"good", were pulled from the licensee's storeroom and installed in the SSPS cabinet.
The resultant test output made, the original symptoms appear worse until the licensee's troubleshooting sequence led to the discovery of the bad cards.
Also compounding the problem was that the bad semiautomatic tester card tested fine on the bench, in the presence of a Westinghouse field engineer.
It was not until the bad car d was loaded into a Westinghouse test cabinet that the bad card was identified.
The licensee spent four days to troubleshoot and satisfactorily complete the SSPS surveillance test.
The licensee's corrective actions were satisfactory.
A "good" semiautomatic tester card was installed and the surveillance on Train A SSPS was satisfactorily performed.
All "bad" test cards that were found were sent to Westinghouse for evaluation and repair.
The results of that evaluation have not yet been received but will be reviewed by the inspector when available. 'reventive actions were incomplete at the close of this inspection.
The licensee's.
preventive action proposals included periodically sending the test cards in the storeroom to the Westinghouse test cabinet to verify proper function.
To summarize the event, on October 7, 1991, IRE technicians found during "pre-surveillance" checks of SSPS that a logic test card was not functioning properly.
The test card was the "semiautomatic tester,"
which functions to automatically sequence testing of a logic circuit within a train of SSPS.
It works in conjunction with a "clock counter" card, which times the sequenced test pulses.
The technicians could not get a good test output from the semiautomatic tester so they decided to replace it with a spare from the storeroom.
The IFE technicians replaced the semiautomatic tester card with one they assumed was good (in fact it was bad)
and the functional check on the card failed again.
After the failure, the technicians reasoned that the clock counter card could be bad, so the decision was made to replace it.,Test results were still unsatisfactory.
Because the T/S allows only two hours for this surveillance test to be complete before a six hour shutdown must begin, and since the actual SSPS logics had not yet been tested, the surveillance was aborted and SSPS was returned to norma l.
The following day, the licensee entered the six hour T/S Action Statement to troubleshoot SSPS.
(Since they were not going to perform the surveillance test, they could not use the T/S allowed two hour grace period.)
ISE technicians began by replacing the second semiautomatic test card since, after some ear lier deliberation, they suspected the card to be faulty.
However, the (third) replacement card from the storeroom was also "bad", and the functional check again failed.
At this point the technicians checked the "bad" and "good" indicating lights on the SSPS cabinet and found the lights did not work properly, although they were noted to work properly earlier in the test.
The licensee found that the installed bulbs used to display the results of 'the functional checks on the SSPS cabinet had bases that were slightly shorter than the bulbs in the other SSPS cabinets.
The licensee verified that the installed bulbs were qualified for nuclear service and had the same model numbers as the
.
bulbs in the other SSPS cabinets, but they observed that Unit 2 Train A bulbs were model No. 1835, identified as being manufactured in England and purchased from General Instrument Corporation.
The normally installed bulbs were also model No. 1835, but purchased from either General Electric or Sylvania.
The licensee installed the correct General Electric No.
1835 bulbs.
The remaining SSPS.
cabinets in Unit 2 and the two trains of Unit I were checked and found to contain General Electric bulbs.
The licensee believed at this point the cause of the SSPS function check failures were the bad bulbs.
The technicians reinstalled the
"original" (bad) semiautomatic tester card and clock counter card and restored SSPS to normal.
After the bulbs were replaced the licensee prepared to do the "full" SSPS surveillance test.
The two hour grace period of Technical Specification 3.3.1. 1 was entered at 10:47 a.m.
(EDT) on October 8, I991.
"Pre-surveillance" functional checks somehow were performed with satisfactory results and the fu11 surveillance was begun.
(In hindsight, the light bulb issue was a
separate unrelated problem.
The real problem remained the bad semiautomatic test, card.)
During performance of the full surveillance, four reactor safeguards logic circuits tested bad.
At the time of this discovery a standing (but blocked) Safety Injection Signal was present in the SSPS.
The technicians began to troubleshoot and noted that the four bad logic circuits were common to a "universal logic" card; The universal logic card is the primary SSPS logic decision circuit which produces all the logic test signals.
The technicians replaced the universal logic card with still unsatisfactory results.
The techniciars next replaced the (good) "safeguards driver" card, also'ommon to the four previously observed
"bad" logic circuits, with a (bad) safeguards driver card from the storeroom.
The safeguards driver card functions to receive actuation signals from the universal logic card to energize master relays, which in turn drive slave relays, that actuate the safeguards protection
equipment.
After the replacement the problem appeared worse; that is, more logic circuits tested
"bad" that had previously tested IIg oo d II Another semiautomatic tester card from the storeroom (also bad)
was installed and again the test failed and more logic circuits tested bad.
At this point the two hour surveillance grace period expired and the licensee entered the six hour shutdown Action Statement of T/S 3.3.1.1.
The licensee had been conferring with Westinghouse engineers shortly after problems began with the SSPS surveillance test.
Through those discussions, the licensee decided they could
"back out" of the surveillance test by manually positioning logic switches in the SSPS cabinets and thereby perform manual testing of SSPS (i.e. without the semiau'tomatic testing and clock counter).
The manual test was successful; all the "bad" logic circuits tested satisfactorily, and SSPS was restored to normal.
Plant shutdown was terminated at 66 percent power and the, Unusual Event that was declared at commencement of the shutdown was terminated.
The next morning a Westinghouse field engineer arrived onsite to assist the licensee in testing a
new semiautomatic test card and clock counter card from the licensee's storeroom.
The ISE staff still suspected that the semiautomatic tester was somehow bad.
The Westinghouse field engineer and the ISE technicians bench tested a
new semiautomatic tester and clock counter with good results, and prepared to install them into the SSPS cabinet.
A troubleshooting flow chart, approved by licensee management, was also developed.
This contained directions (should the new cards also fail) which would guide restoration of SSPS to normal.
The following day, the Iicensee begar, the planned troubleshooting.
Extra data logger s were also hooked up to record various parameters.
The licensee checked the clock counter with an oscilloscope and verified proper pulses.
However, when they checked the semiau'tomatic tester with a visicorder they found that test pulses were not being generated.
Two more "bad" semiautomatic tester cards from the storeroom were insta'1led with unsatisfactory results.
The technicians restored SSPS to OPERABLE by successfully performing the manual logic circuit tests they had performed earlier.
The next day, October 11, 1991, the licensee sent a technician to the Westinghouse simulator to install and test a bad semiautomatic tester card in their SSPS logic cabinet.
The semiautomatic tester card was found bad.with the -same symptoms seen in the, license's logic cabinet.
A known good semiautomatic tester card was then borrowed from Westinghouse and installed in the logic cabinet onsite.
This verified that the only problems were bad cards and insured that a fault in the logic cabinet was not blowing out tester cards.
On October 12, 1991, the licensee placed SSPS in test and installed the
"known good" card that was borrowed from Westinghouse.
This time all logic circuits tested good.
The licensee then removed
C.
that card and installed the sixth, and last, and only "good" semiautomatic tester card from the storeroom.
All logic circuits tested good.
The licensee then finally performed the automtic Train A SSPS surveillance satisfactorily.
On November 6, 1991, the licensee's cold weather preparation activities were inspected to ensure that the licensee has maintained effective implementation of the program of protective measures for extreme cold weather, as committed to in their response to I.E.
The licensee accomplished this under Job Orders No. 48804, 48805 and procedure
"Preventive Maintenance II Environmental gualification Program", rev.l2, September 29, 1988, PM Task No. 30,
"Plant Winterization - Mechanical and Electrical Tasks".
The inspector saw that the licensee did a conscientious job of winter ization and the tasks were properly completed.
The inspector accompanied the licensee's Heating, Ventilation, and air conditioning (HVAC) personnel from the Maintenance Department during completion of the tasks.
The mechanical task consisted of inspecting the Steam Generator stop valve enclosure, backup heating boiler room, screenhouse, service and new office buildings, turbine building, diesel-driven fire pump rooms, emergency diesel generator rooms, 4KV well-water booster pump enclosure and transformer 201 AB and 201 CD deluge houses.
These areas were inspected to ensure vent louvers were closed, proper weather seals on pipe chases and doors were installed, and to check the condition of insulation on piping, walls and roofs.
The electrical task consisted of inspecting the Steam Generator enclosure, screenhouse, turbine building, diesel driven fire pump, RWST valve houses, visitor center well water booster pump enclosure and transformer 201 AB and 201 CD deluge house to ensure space heaters and heat tape were operating properly.
Overall the space heaters and heat tape were operating at the appropriate temperatures, the door seals were properly installed and the piping insulation was in verv good cordition.
No violations, deviations, unresolved or open items were identified.
5.
En ineerin and Technical Su ort (71710)
The inspector monitored engineering and technical support activities at the site and, on occasion, as provided to the site from the corporate office.
The purpose of this monitoring was to assess the adequacy of these functions in contributing properly to other functions such as operations, maintenance, testing, training, fire protection and configuration management.
On November ~9-21, 1991, a complete walkdown of the Unit 2 safety injection system (SIS)
was performed.
This was accomplished using the licensee's procedure
"Placing Safety Injection (SI) System in Standby Readiness,"
OHP 4021.008.002, Rev. 8, March 23, 1991, and Emergency Core Cooling Flow Diagram Nos.
OP-2 5129, 5131a, 5142, 5143, and 5144.
The inspection was performed to verify the proper valve lineup and the
accuracy of the affected drawings.
As a result of the inspection, one miror discrepancy between a drawing and the actual piping was identified.
The licensee's document control group was notified of the discrepancy and noted followup action would be taken.
The inspector noted that all valves appeared clearly and correctly labelled, and all instruments were within'alibration dates.
This inspection was performed by comparing the flow diagrams with the actual piping of the SI system, from the refueling water storage tank to the containment penetrations.
Every valve outside of containment was verified to be in the location shown on the drawing and in the correct position.
For valves which had remote position indication, the remote indication and actual position were compared.
Valves inside of containment were verified by checking the control room position indicators.
The one discrepancy found was on drawing No. OP-2-5142.
On the drawing, safety valve SV-96 is shown as connected to the suction line to the North Safety Injection Pump (PP-26N), while it is actually connected to the suction line to the South Safety Injection Pump (PP-26S).
The licensee stated the drawing would be reviewed.
No violations, deviations, unresolved or open items were identified.
Act'ions on Previousl Identified Items (92701)
(Closed)
Open Item 315/90007-01; 316/90007-01:
Review of root cause analysis of loose anti-shock springs for its potential to be a generic problem.
The inspector reviewed Problem Reports Nos.89-250, 90-0415, and 90-0406 for the licensee's root cause analysis and found the loose anti-shock springs to be isolated cases which did not indicate a generic problem.
The inspector also reviewed procedure
"ITE 4 KV Power Circuit Breaker flaintenance,"
- 12 THP 5021.ENP.012, Rev.
0, October 29, 1991 (this replaced procedure
"Inspection and Repair of 4KV Circuit Breakers,"
- 12 tlHP 5021.082.001, rev.
7) to see if a suggested Step 7.1.3 had been added to open the circuit breaker and discharge the closing springs.
The change was incorporated.
No further questions exist and this open item is considered closed.
No violations, deviations, unresolved or open items were identified.
NRC Bulletins (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.
(Closed)
NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification."
On December 20, 1988, the NRC issued IE Bulletin 88-11 which requested each utility to establish and implement a program to confirm pressurizer surge line integrity considering the occurrence of= thermal stratification.
In June 1989, the Westinghouse Owners Group (WOG) issued report WCAP-12277, which provided a response to IE Bulletin 88-11 on pressurizer surge line thermal stratification.
Specifically, this report provided a generic justification for continued operation (JCO) for.all domestic Westinghouse plants to operate for at least 10 additional heatup and cooldown cycles.
After the completion of that generic report, Westinghouse began preparing a generic, detailed analysis for the WOG.
Since a single bounding analysis could not conservatively bound the various configurations found at each of the Westinghouse plants, Westinghouse grouped the plants based on structural layout and operational techniques.
In spite of the grouping approach, conservative, enveloping assumptions were necessary for various parts of the analysis.
As a result of these assumptions, as well as plant specific fill and vent operations performed at D. C. Cook, the generic WOG analysis was not sufficient to show acceptable fatigue life for the D. C. Cook Units I and 2.
The licensee retained Westinghouse to pursue the issue and a
plant-specific JCO was derived and provided to the licensee and NRC via a Westinghouse letter dated June 28, 1990.
The JCO concluded that operation of D.
C.
Cook Units I and 2 remained acceptable pending the detailed plant-specific analysis required by IEB 88-11 (Ref.
NRC Inspection Report 50-315/90013(DRP);
50-316/90013(DRP)).
By letter dated March 19, 1991, the licensee submitted to the NRC a
plant specific analy'sis (WCAP-12850) for the Donald C.
Cook Nuclear Plant, Units 1 and 2.
The analysis was reviewed by the NRC staff and its consultant, Boo khaven National Laboratory, and found acceptable.
IER 88-11 is therefore considered complete at D.
C.
Cook.
No violations, deviations, unresolved or open items were identified.
Yang ement Heetin A management meeting, attended as indicated in Paragraph 1.a.,
was conducted at the D.
C.
Cook site on November 22, 1991.
The purpose of 'the meeting was to discuss licensee performance and initiatives.
The topics presented by the licensee staff were:
AEP nuclear short and long term goals Engineering and technical support Reorganization Individual Plant Evaluation project Progress in the maintenance area
self assessments Outage Risk t1anagement The licensee responded to numerous NRC questions, and various informal discussions on the above and related topics occurred.
9.
Mana ement Interview The inspectors met with licensee representatives.(denoted in Paragraph 1.b)
on December 3, 1991, 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.
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