IR 05000315/1994024
| ML17332A574 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 02/10/1995 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17332A573 | List: |
| References | |
| 50-315-94-24, 50-316-94-24, NUDOCS 9502210151 | |
| Download: ML17332A574 (25) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
y Report Nos.
50-315/94024(DRP);
50-316/94024(ORP)
Docket Nos. 50-315; 50-316 Licensee:
Indiana Michigan Power Company 1 Riverside Plaza Columbus, OH 43216 License Nos.
OPR-58; OPR-74 Facility Name:
Donald C.
Cook Nuclear Power Plant, Units 1 and
Inspection At:
Donald C. Cook Inspection Conducted:
December Site, Bridgman, MI-I 17, 1994 through January 30, 1995 Inspectors:
J.
A. Isom D. J. Hartland C. N. Orsini R. L. Bywater Approved By:
May'ne J. g opp, Chief Date
'eactor/rejects Section 2A I
ct on mrna ns ect'o f e
emb 1994 throu h Januar
1995 e o t os.
50-315 94024 ORP 50-316 9 024 ORP d:
R tt, d
ytyt d tt by t td t d
region-based inspectors of: action on previous inspection findings, operational safety verification, onsite event follow-up, current material condition and housekeeping, cold weather preparation, radiological controls, security, regional requests (Temporary Instruction (TI) 2515/126 Evaluation of Online Maintenance; Temporary Instruction 2515/125 Foreign Material Controls), maintenance activities, LCO management, surveillance activities, Unit 1 fuel failures and thimble tube modifications.
geesu ts Of the 13 areas inspected, three inspection follow-up items were identified that pertained to the effectiveness of the licensee's actions to prevent foreign material intrusion into the reactor vessel (paragraph 4.b.);
determination of whether entry into certain boration Technical Specifications (TS) were required when the Unit 1 "CD" diesel generator was removed from service (paragraph 5.a.l));
and inspectors'eview of gu'idance provided in Operation Standing Order 95 (paragraph 5.a.2)).
Additionally, one unresolved item was identified that pertained to the li ensee's reportability evaluation of the loss of charging system cross-tie capability from Unit 2 for support of Unit 1 shutdown functions (paragraph 3.b).
Based upon this inspection, TIs 2515/125 and 2515/126 were closed.
The following is a summary of the licensee's performance during this inspection period:
9502210i5i 950210 PDR ADOCK 050003i5
Plant 0 erations:
Overall, operator performance during this period was good.
Operators reduced power on Unit 1 to repair a leak on the feedwater piping and increa'sed power on Unit 2 to 100 percent with no significant operational events.
Additionally, the operators responded well to the balance of plant transient from a stuck open condensate booster pump discharge check valve.
While the technical specifications permits unit operation with two of the power operated relief valves (PORVs) isolated, Operations department management shar ed the inspectors'oncern of prolonged Unit 1 operation in this condition and took actions to have one of the two PORV block valves restored to service.
Overall, plant housekeeping and material condition was very good during this period.
ai te a c and S
ve la ce Overall, performance during the period was good.
The inspectors continued to review the effectiveness of the licensee's management of Limiting Conditions for Operations (LCO) for Technical Specification equipment and systems.
There were additional questions associated with whether the operators'hould have entered TS 3.1.2.2.a.
'ssociated w'ith the boric acid flowpath and TS 3. 1.2.6 associated with the boric acid pumps when the Unit 2 "CO" diesel generator was taken out of service for planned maintenance on January 3, 1995.
Although the licensee's foreign material control program was adequate, some foreign material have been found in the lower core plate region of the reactor vessel during refueling outages.
e a
d ec
u t
The licensee was conducting an investigation into the causes for the Unit 1 fuel failures.
Also, a minor modification, which was completed during the 1992 refueling outages, to stop thimble tube leakage was found to be successfu i I
It
DETAILS Persons Co tacted:
merican Electric Power Service Com an AEPSC 8H. S. Ackerman, Senior Engineer 8G.
D. Hines, Senior Engineer W. T. HacRae, Senior Engineer 8R.
S. Siada, Engineer I I d a
a Mich'
owe Cook Nuc e a t A. A. Blind, Site Vice President/Plant Hanager
- K. R. Baker, Assistant Plant Hanager/Operations Superintendent
- L. S. Gibson, Assistant Plant Hanager-Technical J.
E. Rutkowski; Assistant Plant Hanager, Support
- W. J.
Flaga, Haintenance Department-Production Supervisor D. L. Noble, Radiation Protection Superintendent T. K. Postlewait, Site Engineering Support Manager
- J. S. Wiebe, guality Assurance 5 Control Superintendent L. H. Vanginhoven, Project Engineering Superintendent
- H. J. Stark, Plant Engineering Section Supervisor N. L. St.
Amand, Hechanical Engineering Section Supervisor W. H. Hodge, Plant Protection Superintendent
- R. A. West, Licensing Coordinator
- H. Depuydt, Licensing Coordinator G ne a
Ph sics C
na Cor oration:
8R. Stanley, Hechanical Group Director Nuc ear Re u ator Commiss on 0J.
A.
8V. P.
8W. D.
fH. A.
8R. A.
Isom, Senior Residept Inspector, D. C.
Cook Lougheed, Reactor I'nspector Shafer, Chief, Haintenance and Outage Section Walker, Reactor Inspector Westberg, Reactor Inspector iDenotes those individuals attending the service water operational performance inspection (SWSOPI) meeting on January 19, 1995.
- Denotes those individuals attending the exit interview conducted on January 30, 1995.
The inspectors also had discussions with other licensee employees, including: members of the technical and engineering staffs, reactor and auxiliary operators, shift engineers and foremen, maintenance personnel, and contract security personne ction on Previous Ins ect'on Fi din s:
(92701)
'a 0 b.
osed Ins ectio Fo low-Item 50-315 94002-03 D
50-ih t
h d ddi i i
i h
use of the condition reporting system by plant operators to address equipment problems.
Plant operators had not promptly written a condition report (CR) following a Unit 2 turbine trip during plant startup on January 26, 1994.
However, the shift test advisor wrote CR 94-120 to document the pressure fluctuations on the main lube oil and the emergency oil circuits which was believed to be the cause for the turbine trip.
Plant Manager Instruction (PMI) 7030, "Corrective Action," Rev.20, October 7, 1994, described the licensee's policy for identifying and evaluating condition reports.
The procedure stated that condition reports shall be written for adverse condition or events.
Examples listed in the PHI included equipment malfunctions, defined as a compon'ent that acts differently"from expectations and in a manner that adversely affects its safety function.
The inspectors found no further instances when the licensee failed to generate a condition report to address significant equipment problems.
This item is closed.
d s ec o
o
-
tern 50-315
-04
~l-OR:
ih Od ti
'Od t
t d
ttt h
provided management coverage for startup of Unit 2 in January 1994 had little operational experience.
The licensee revised procedure OHI 4013,
"Operators: Authorities and Responsibilities,"
Rev. 7, December 21, 1993, with a change sheet dated September 23, 1994.
The change sheet added steps to section 4.7,
"Operations Management Oversight During Critical Evolutions."
Section 4.7 listed turbine roll and reactor startup/shutdown as examples of critical'lant evolutions that may require oversight by senior operations department management personnel.
Section 4.7 also listed the positions of operations department senior managers who were authorized to provide coverage during critical plant evolutions.
The inspector has observed appropriate operations department management coverage during subsequent critical plant evolutions.
This item is closed.
C.
0 en V olation 50-315 9 018-01 DRP 50-3 6 940 8-01 D
P This item concerns the failure of the licensee to remove action request tags from plant components upon resolution of the deficiencies documented on the tags.
,In response to the violation, the licensee committed to implement a different method for documenting and accounting for the use, location, and removal of the tags.
The licensee committed to implement the process change by June 1,
1995.
In the interim, the licensee sensitized their personnel to the existing circumstances and expectations.
During this inspection period, the inspectors identified 4 tags which required removal:
~
AR¹ A86114:
"Hain Turbine Aux Lube Oil Pump Will Not Stop" (located in the Unit 2 control room (CR))
~
AR¹ A85895:
"2-FHO-242 Indicates Intermediate" (located in the Unit
CR)
~
AR¹ A80526:
"ESW Strainer Outlet Gate Failed To Switch" (located in the Unit
CR)
~
AR¹ A81387: "Starting Air Compressor Safety Leaks" (located at the local emergency diesel generator panel)
Additionally, the shift operators identified several examples, which were documented in CR¹'s 95-0097, 95-0137, 95-0138, and 95-0139.
Although this condition has not yet led to a significant safety concern, failure to remove the tags'ould potentially result in an inaccurate assessment of the status'f plant equipment by the reactor operators.
In response to the inspectors'oncerns, the licensee agreed to reassess the interim actions taken.
The inspectors will continue to monitor this situation to verify that the actions taken will prevent recurrence.
C osed s
e t low-u te 50-315 940 0-03 50-3 6 94020-03 D
The inspectors were concerned with the licensee's engineering approach to address a recent industry event in which loose control rod drive (CRDH) funnels and pins, which retain these funnel in place, have caused equipment damage or malfunction.
Additionally, the inspectors were concerned with what appeared to be lack of familiarity with the loose funnel issue and the vendor recommended actions by the corporate engineering department during a telephone conference on October 21, 1994..
Based on the fact that tho corporate engineers had.not recommended any inspection of the funnels for the Unit 2 outage to verify that the funnels were not loose, the inspectors determined that the engineers had initially concluded that loose funnels were not an issue.
Therefore, only a visual inspection of the CRDHs was recommended.
The engineers'ecision was based on past unit performances and on a Westinghouse failure analysis.
This analysis showed that a funnel coming loose at power would not impose any additional safety problem as it was already addressed by the Westinghouse loose parts analysis for the reactor coolant system.
How'ever, on October 16, 1994, corporate engineers decided to reevaluate their initial inspection recommendation when penetration no. 76, one of five thermocouple penetrations, was
found with no retaining pin (CR 94-2141).
The as-found condition of penetration no.
76 raised some doubt on the quality of installation for the other funnels.
Consequently, the engineers reconsidered their initial approach to the funnel issue and recommended that plant personnel check all funnels for looseness.
The licensee initially used robotics for most of these looseness inspections.
However, there were 9 funnels which could not be inspected robotically because of their proximity to the outer periphery of the reactor vessel head assembly.
When these
penetr ations were inspected manually by two engineers from the plant, the engineers raised a concern with what they perceived to be excessive looseness of the funnels (CR 94-2167).
Because the Westinghouse
"consequenced-based" analysis of the loose funnels was found to be unacceptable, decision was made to perform a manual rotational check on all funnels to quantify the degree of looseness.
The inspection found that 42 funnels rotated, with maximum rotation of about an eighth of an inch, and that 11 funnels were tight.
After Westinghouse was able to provide a reduced weld specification, the licensee welded all the loose funnels, with total exposure to all personnel of about 5.3 REH.
The repairs were completed on 23 October, 1994 under minor modification 02-MH-580.
Interviews with the engineers indicated that the engineers were.
well aware of the problems occurring in the industry related to this event.
The engineers were aware of the Westinghouse advisory letter, dated January 28, 1994, and problems identified at Braidwood in April of 1994 and at Sequoyah in July of 1994.
The inspectors were informed that the engineers were not prepared to discuss the loose funnel issue on the telephone conference on October 21, 1994, because they were involved in another meeting with Westinghouse engineers to discuss the CROM weld penetration cracking issue for most of the day.
The inspectors were informed by an engineer that the licensee had not made a commitment to weld repair the ll funnels during the Unit 2 outage in 1996 as stated in paragraph 5.b of inspection report 50-315/94020(ORP);
50-316/94020(DRP)..
At the end of the
'nspection report, the engineers were determining whether the remaining ll funnels required weld repair during the U2 1996 outage or whether the repair could be postponed to an outage in 1997.
The inspectors will review future licensee repair plans with regard to
U2 CROM funnels which were not welded during the Unit 2 1994 outage and the licensee's planned actions with regard to the Unit
CRDM funnels.
OPEN Ins ect on Fo low-u Item 50-316 94022-01 DR
As discussed in paragraph 5.a.3) of Inspection Report 50-315/94022(DRP);
50-316/94022(ORP),
the recent Unit 2 refueling outage was extended by approximately 45 days due to emergent wor f
This item was initiated in order to determine if ineffective maintenance during the outage contributed to the emergent work.
Two examples were specifically cited: repair of residual heat removal (RHR) to safety injection cross-tie valve IHO-316 (CR 94-2472),
and replacement of leaking steam generator (SG)
manway cover gaskets (CR 94-2414).
Four manways for SGs 22 and 23 were removed during the Unit 2 refueling outage to support eddy current testing.
Prior to re-installation, the licensee discovered ga'skets with two different vendor part numbers under one licensee stock number.
Following a recommendation from the vendor, the licensee installed gaskets with a Unit 2 part number in SGs 22 and 23. All four manways developed leaks during the subsequent reactor coolant system pressurization.
The licensee then sent one of each gasket type to the vendor for further analysis.
The vendor determined that although the gaskets were identical in dimension, the Unit 1 gaskets had more spirals in the asbestos filler material (approximately 30 spirals compared to 15 in the Unit 2 gaskets).
Based on this, the vendor indicated that the gaskets with the Unit 1 part number were appropriate for both Units 1 and 2.
The licensee installed the gaskets with the Unit 1 part number and have had no further problems.
The inspectors have no further concerns with regards to the licensee's maintenance activities on SG manways.
This item will remain open pending NRC review of CR 2472 concerning IH0-316.
No violations or deviations were identified.
3.,
Plant 0 erations:
Unit 1 was operating at 100 percent power at the beginning of the inspection period.
Unit 1 commenced power reduction to 55 percent on January 13 to repair a steam leak on the weld which connected the short section of one inch pipe from a vent valve, FW-248, to the Unit 1 West Hain Feedwater Pump discharge header piping.
The steam leak was repaired and the Operators returned Unit 1 to 100 percent power on January 16, 1995.
Unit 1 continued"to operate at 100 percent power with no significant operational problems for the remainder of the inspection pe}'iod.
Unit 2 was operating at 48 percent power at the beginning of the inspection period.
Unit 2 remained at 48 percent power level until the second main feed water pump was restored to service and while power escalation testing was completed.
Operators commenced power escalation on December 21, 1994, and Unit 2 was at 100 percent power on December 28, 1994.
Unit 2 continued to operate at 100 percent power with no significant operational problems for the remainder of the inspection perio erational Safet Veri ic tio '71707)
The inspectors verified that the facility was being operated in conformance with the licenses and regulatory requirements, and that the licensee's management control system was effective in ensuring safe operation of the plant.
On a sampling basis the inspectors:
verified proper control room staffing and coordination of plant activities, verified operator adherence with procedures and technical specifications, monitored control room indications for abnormalities, verified electrical power was. available, and observed the frequency of plant and control room visits by station management.
The inspectors reviewed applicable logs and conducted discussions with control room operators throughout the inspection period.
The inspectors observed a number of control room shift turnovers.
The turnovers were conducted in a professional manner and included log reviews, panel walkdowns, discussions of maintenance and surveillance activities in progress or planned, and associated LCO time restraints, as applicable.
The inspectors made the following observations with regards to operator performance during the inspection period:
I)
On December 29, 1994, the operators found that the insulation on valve, 2-FM0-203, was wet.
When the insulation was removed, the licensee found that the valve had a through-wall, pin-hole leak.
The leak was stopped by
"peening" over the hole.
Condition report 94-2583 was written to document this condition.
Valve 2-FMO-203 is a feedwater isolation valve to the no.
steam generator on Unit 2, which isolates within 20 seconds upon receiving a safety injection signal.
This valve is also an Inservice Inspection (ISI) Code Class 2 valve and therefore, is inspected and tested in accordance with the plant's ISI valve pro,*ram.
After the licensee had peened the valve body, the engineers performed an ultrasonic examination of a 2 inch radial area around the leak to characterize the amount of 'valve material left around the leak.
The engineers found that the valve material thickness ranged from 2 to 2.5 inches and therefore, structural integrity of the valve was in a satisfactory condition.
Consequently, the licensee concluded that the leak was not caused by erosion/corrosion of the valve body and that the likelihood of a.catastrophic failure of the valve was minimal.
The licensee, resident inspectors, and members of Nuclear Reactor Regulation (NRR) and Region III staff discussed
.the nature of the leak and the licensee's repair plans during a
January 4,
1995 telephone conference.
During the conference call, the licensee stated that the nature of the leak was
such that no repairs, other than what was already
.
accomplished through the peening process, were war anted.
The licensee planned to operate the valve in the present condition with the additional requirement for the operators to monitor the valve for leakage twice a day.
The licensee submitted a letter to NRR (AEP:NRC:0969AB),
dated January 5,
1995, to request relief from the requirements of the ASHE Section XI Code in order to allow deferral of the repair of the pin-hole leak on valve, 2-FHO-203.
The licensee was planning to submit to the Office of NRR the repair methodology for performing a weld patch on the valve in the event the leak recurs.
The inspectors will continue to monitor the condition of 2-FMO-203 until the next Unit 2 refueling outage in 1996.
The operators responded well to a balance of plant transient on January 5; 1994, in which the "North" condensate booster pump tripped.
When the condensate booster pump was stopped and the control switch for the pump was placed in the "auto" position, the pump immediately restarted because of a low condensate pump discharge header pressure.
The low header pressure was caused by the stuck open discharge check valve associated with the "North" condensate booster pump.
The operators started a middle hotwell pump to mitigate the loss of condensate and subsequent steam generator water level transient.
The event was terminated when the "North" condensate booster pump discharge valve was manually closed.
The operators wrote CR 95-0078 to document the check valve failure and initiated Action Request A-87626 to have the check valve repaired.
During a routine resident tour of the Unit 1 control room on January 13, 1995, the inspectors observed that two power-operated relief valves (PORVs) were isolated with Unit
operating at 100 percent and questioned the circumstances
.
surrounding the isolation of a PORV, NRV-153, to the Uni-t-'1 pressurizer on January ll, 1995.
The inspectors were concerned that with two of the three PORVs isolated, a
potential for the pressurizer code safety valves to be challenged existed.
The inspectors'iscussion with the senior onsite managers found that the managers agreed with the inspectors'oncerns.
The managers took actions to have 1-NRY-153 restored to operable status several hours later.
At about 1100 on January ll, 1995, an auxiliary relay for NRV-153, 1-33X-NRV-153, failed and resulted in some smoke in the control room.
In response, the operators removed control power to NRV-153, shut its associated block valve, NHO-153 and initiated a priority 10 action request.
Instrumentation and Control (I&C) technicians replaced the damaged relay with one obtained from the storeroom under job
order (JO) no.
C0027907.
The auxiliary relay provided the position of NRV-153 to the primary plant computer.
At the time the operators shut NM0-153, a second block valve, NMO-151, to another PORV, NRV-151, was already isolated because NRV-151 had exhibited minor seat leakage.
The operators declared 1-NRV-153 operable at 1:05 PH on January 11, 1995 after the ISC technicians informed the control room that the relay was replaced.
However, when the I8C technicians discussed the relay replacement with the IEC planners, they were informed that the damaged relay was classified as nuclear safety-related (NSR)
and further, that the relay that was obtained from the storeroom was a non-NSR relay.
Consequently, the operators again declared PORV, 1-NRV-153, inoperable at 2:50 PH on January ll, 1995, and shut the PORV 'isolation valve.
The corporate engineers found a spare relay, which had previously been removed from service, in the PORV control circuit.
They recommended that the plant personnel use the spare relay in lieu of dedicating the installed non-safety grade relay.
The non-safety grade relay was replaced with the spare safety-grade relay to NRV-153, and the PORV was restored to service at 12:40 PH on January 13, 1994.
The inspectors verified that the operation of Unit 1 at power with one PORV isolated for leakage and another PORV isolated for other than leakage was allowed by Unit 1 Technical Specifications (TS) 3.4.11.
b.
Onsite Event Follow-u
(93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to
CFR 50.72.
The inspector pursued the events onsite with licensee and/or other NRC officials.
In each case, the inspectors+v'erified that any required notification was correct and timely.
The inspectors also verified that the licensee initiated prompt and appropriate actions.
The specific events were as follows:
During review of the licensee's investigation of condition report (CR) 94-2162, the inspectors had some questions regarding the justification documented for classifying it as not reportable..
The licensee initiated the CR on October 20, 1994, to document hourly fire watches which were inadvertently released while CVCS cross-tie capability from Unit 2, for support of Unit 1 shutdown functions, was unavailable.
With the cross-tie flow path unavailable, the licensee was providing equivalent shutdown capability by performing the fire watches in the affected areas of Unit 1 as required by TS 3.1.2.3.'he inspectors'urther review
e
't
of the licensee's reportability evaluation is an unresolved item (50-316/94024-01).
Current Material Condition and Housekee in : (71707)
The inspectors performed plant and selected system and component walkdowns to assess the general and specific material condition of the plant, to verify that work requests had been initiated for identified equipment problems.
Walkdowns included an assessment of buildings, components, and systems:
identification, tagging, accessibility, fire and security door integrity, scaffolding, radiological controls, and unusual conditions.
Unusual conditions included but were not limited to water, oil, or other liquids on the floor or equipment; indications of leakage'through ceiling, walls or floors; loose insulation; corrosion; excessive noise; unusual temperatures; and abnormal ventilation and lighting.
The inspect'ors also monitored the status of housekeeping and plant cleanliness for fire protection and protection of the safety-related equipment from intrusion of foreign matter.
The inspectors observed that overall plant housekeeping and material condition was very good during the inspection period.
Cold cather Pre aration (71714)
The inspector reviewed and verified the implementation of the licensee's program to prepare the plant for cold weather.
These activities were controlled under MHP5030 PH TASK 30, "Preventive Maintenance, Plant Winterization 8 Dewinterization."
Temporary Modifications 1-94-50 and 2-94-36, implemented to cover drain holes in the east main steam enclosure rooms of units 1 and 2, respectively, were also reviewed.
The licensee planned to implement a permanent modification to correct this condition prior to 1996.
The inspectors did not identify any concerns in this area.
Radiolo ical Control~s:
(71707)
The inspectors verified that personnel were following health physics procedures for dosimetry, protective clothing, frisking, posting, etc.,
and randomly examined radiation protection instrumentation for use, operability, and calibration.
~Securit
(71707
& 81070)
Each week during routine activities or tours, the inspectors monitored the licensee's security program to ensure that observed actions were being implemented according to the approved security plan.,
The inspectors noted that persons within the protected area displayed proper photo-identification badges and those individuals requiring escorts were properly escorted.
The inspectors also verified that checked vital areas were locked and alarmed.
Additionally, the inspectors also observed that personnel and packages entering the protected area were searched by appropriate equipment or by hand.
No violations or deviations were identified.
Re ional Re uests:
(92701)
Closed val t o o
On-e ntenance 5 5
In response to a request from the Region III Office, the inspectors conducted a review of the licensee's procedures and practices regarding the removal of equipment from service for on-line scheduled maintenance to determine if the impact on plant safety was appropriately considered.
The review was conducted per the guidance contained in NRC Inspection Manual Temporary Instruction 2515/126.
The inspectors concluded that the licensee had administrative controls in place for planned maintenance management which were effective for minimizing the impact of out-of-service equipment on plant safety.
These controls included: coordination of planned maintenance with other maintenance and testing activities and operating conditions by using a 12-week, structured, functional equipment group (FEG)/system train schedule; implementation of guidelines to minimize the frequency and duration of entries into Technical Specification limiting conditions for operation (LCOs);
and implementation of Standing Order PMS0.122,
"Voluntary Removal of Technical Specification Required Equipment, Vital Secondary Equipment and Fire Protection Equipment," which provided a
formalized process for staff planning and plant management review/approval of voluntary LCO, entries.
The structure of the FEG/system train schedule limited the possibility of concurrently performing voluntary maintenance on multiple systems within a safeguards train.
The licensee identified an area where improvement in the PMS0.122 process was needed when it identified in Condition Report No. 94-2452 that a Unit 2 boric acid filter replacement work activity had been added to a previously-reviewed PMS0.122 LCO work list without the same level of review as the original work plan.
The result was an unplanned extension of an approved 17-hour LCO entry by 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br />.
The inspectors'eview of this event is discussed in inspection report 50-315/94022(ORP);
50-316/94022(DRP).
The licensee had also established cumulative system unavailability goals for the emergency core cooling systems, emergency diesel generators, and auxiliary feedwater system, with consideration given to unavailability assumptions used in the probabilistic risk assessment (PRA) performed for its individual plant examination
(IPE).
The licensee used the goals as a tool in the review process for approval of LCO entries for these systems.
Other licensee activities that were in progress or planned included a self-assessment of on-line maintenance practices, the development of an "equipment configuration matrix" from PRA studies to identify combinations of equipment which contribute to risk significantly if out-of-serv'<ce concurrently, and a review of actual versus IPE-assumed equipment unavailability for systems.
Closed Fo ei terial Contro s
I 5 5 125 The inspectors reviewed the licensee's procedures listed below and determined that they adequately addressed provisions for material accountability to ensure loose items were not inadvertently left inside systems after work activities were complete:
PHP 2220 SCC.003,
"System Cleanliness Hethods,"
which contained requirements for maintaining cleanliness of systems opened for maintenance.
PHP 2220 SCC.001,
"Cleanliness Inspection Criteria,"
which provided guidance for classification of systems for cleanliness, and provided cleanliness acceptance criteria and requirements for documenting inspections.
PHI 4080,
"Control of Non-Core Objects in the Spent Fuel Pool and Transfer Canal," which established these areas as foreign material exclusion zones.
PHSO. 145,
"Logging of Tools During Refueling Outages,"
which contained requirements relative to logging and control of tools when entering the refueling accountability area in upper containment.
The inspectors ~observed maintenance 'activities in'progress in the plant and did not identify any examples of failure to follow the procedural requirements.
However, the inspectors reviewed condition reports for the last year and noted examples of failure to follow procedures with regards to foreign material exclusion zone requirements and failure to cover unoccupied open systems during maintenance activities.
None of these conditions resulted in significant events.
However, the inspectors will continue to monitor these activities to ensure that an adverse trend does not develop.
In addition, the inspectors reviewed Condition Reports 94-0669 and 94-2152 for Units 1 and 2, respectively, which documented licensee
'dentification of foreign material on the lower reactor vessel core plate prior to core reload during the last refueling outage for each unit.
The licensee removed all foreign material from the
reactor vessel before commencing fuel reload.
The inspectors were informed that the licensee believed that the material had entered the reactor vessel during the refueling outage period based on activity level of the materials.
Review of future core inspections to assess effectiveness of the licensee actions to prevent foreign material intrusion in the core is an inspection follow-up item (50-315/94024-02(DRP);
50-316/94024-02(DRP)).
No violations or deviations were identified.
aintena ce Surveillance:
(62703 5 61726)
a 0 aintena ce Act v'ties:
(62703)
Routinely, station maintenance activities were observed and/or reviewed to determine compliance with approved procedures, regulatory guides, industry codes, industry standards, and Technical Specifications (TS).
The following items were also considered during this review:
Limiting Conditions for Operation requirements met while components or systems were removed from service; approvals obtained prior to initiating work; functional testing and/or calibrations performed prior to returning components or systems to service; maintenance of quality control records; and activities accomplished by qualified personnel.
Portions of the following Job Order (JO) activities were observed and reviewed:
JO C17176,
"Check Lever and Fuel Pump Control Rack Position."
JO R0020809,
"Replace Expansion Joint l-gT-102CD."
Job Order C0026081,
"Disassemble, inspect, repair as necessary 1-T-131-7" Job Order R0032821,
"Calibrate Pressure Switch, 1-XPS-305" Job Order C0027782,
"Uncouple and Replace 1-PP-3E-MTR (Electrical Motor for the Unit 1 East Motor-Driven Auxiliary Feedpump)"
'I LCO Mana ement:
The inspectors reviewed the licensee's planned maintenance activities that required entry into TS LCO action statements.
The inspectors reviewed two maintenance activities that were performed.
in accordance with PMS0.122,
"Voluntary Removal from Service of Technical Specification Required Equipment, Vital Secondary Equipment and Fire Protection Equipment."
PMS0.122 is designed to ensure that licensee management approval is obtained prior to entering an LCO to perform maintenance.
1)
On January 3,
1995, at 3:00 a.m.,
a voluntary entry into Technical Specification (TS) 3.8. 1. 1 was made to perform maintenance on the Unit 2 CD emergency diesel generator (EDG).
The no.
3 boric acid transfer (BAT) pump was not declared inoperable when its emergency power supply (the Unit 2 CD EDG) was taken out of service.
The Shift Supervisor (SS)
on duty reviewed TS 3. 1.2.6 (Boric Acid Transfer Pumps Operating) prior to tagging out the EDG, but did not consider the 0'3 pump inoperable.
The SS also noted that the action statement for TS 3.1.2.6 was similar to TS '3.8. 1.1.
(72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> duration).
Following shift turnover approximately three hours later,-
the oncoming Shift Supervisor identified that in addition to TS 3.8.1.1, TSs 3.1.2.6 and 3.1.2.2.a should have been entered because of an inoperable no.
4 BAT pump.
These LCOs were entered at approximately 8:30 a.m.,
and condition report CR 95-0010 was written.
The licensee's preliminary investigation for CR 95-0010 has determined that entry into TSs 3. 1.2.6 and 3.1.2.2.a was not required.
This issue will be an Inspection Follow-up Item pending licensee completion of CR 95-0010 and further NRC review (316/94024-03).
2)
On January 4,
1995, the Unit 1 north safety injection pump was removed from service for maintenance.
Due to the scope of planned work, it was necessary to also make the "E" RHR pump inoperable by taking its control switch to the pull-to-lock position.
This was necessary due to guidance documented in OS0.095,
"Four Loop Injection Requirements and Possible Loss of RHR mini-Flow," to preclude the possibility of dead-heading an RHR pump, while ensuring four loop injection capability.
The inspectors'eview of the guidance provided in OS0.095 will be an Inspection Follow-up Item pending further NRC review (315/94024-04;316/94024-04).
Surveillance Activ'ties:
(61726)
During the inspection period, the inspectors observed technical specification required surveillance testing and verified that testing was performed in accordance with adequate procedures, instrumentation was calibrated, results conformed with technical specifications and procedure requirements and were reviewed, and any deficiencies identified during the testing were properly resolved.
The inspectors also witnessed portions of the following surveillances:
02-OHP 4030.STP.018,
"Steam Generator Stop Valve Dump Valve Surveillance Test," Revision 7.
02-IHP 4030.STP.510,
"Reactor Trip SSPS Logic and Reactor Trip Breaker Train "A" Surveillance Test (Monthly)," Revision
15
No violations or deviations were identified.
En ineerin 8 Technical Su ort:
(37700)
The inspector monitored engineering and technical support activities at the site including any support from the corporate office.
The purpose was to assess the adequacy of these functions in contributing to other functions such as operations, maintenance, testing, training, fire protection, and configuration management.
'a ~
Unit 1 Fuel Leak:
The inspectors discussed the licensee's ongoing investigation into the elevated reactor coolant activity level observed in Unit
(CR 94-1987 and CR 94-1720).
The Unit
activity level is about 1.00 E-02 microcurie of Iodine-131 per cubic centimeter (cc).
Past activity level has been one to two orders of magnitude lower than the present activity level.
The licensee has formed a "Failed Fuel Cause Evaluation Team" to determine the causes for the fuel defects.
The licensee estimated that a total of five fuel defects exist in assemblies currently in Unit 1.
The team's visual examination of the failed fuel pins indicated that possible cause for the failure maybe due to fretting of the fuel pin cladding by the gridstraps.
At the end of the inspection report, the licensee was working with the fuel vendors to. examine the possible causes for the fuel failures.
The inspectors will continue to monitor the licensee's investigation of this issue.
b.
Thimble Tube Modi ication:
The licensee initially experienced problems with premature thimble tube wear during the Unit 2 cycle 6-7 refueling outage (RFO).
During the 1992 RFO, the licensee replaced 15 and 22 thimble tubes for Units 1 and 2 respectively.
The replacement thimble tubes were chrome plated at axial locations corresponding to the lower core plate and fuel assembly lower nozzle area, where, most of past thimble tube wear was o'erved.
The thimble tube wear, was thought to be vibration-induced.
During the 1994 refueling outages, eddy current inspection of the chrome plated thimble tubes installed during the 1992 RFOs showed that replacement thimble tubes showed no indication of wear on the plated portions of the tubes.
Active indication of wear continued to be observed on the other thimble tubes.
Based on eddy current inspection results from the 1994 RFOs, the licensee planned to replace all thimble tubes with chrome plated tubes.
Also, to address wear indication at the axial tube location corresponding to the'ower core support dome and diffuser plate in the lower internals, the new tubes will be chrome plated over a longer length.
The licensee planned to complete the design change for both units by the end of the RFOs in 1997.
Additionally, the licensee
planned to perform a
100 percent thimble tube inspection during each RFO to evaluate the effectiveness of the chrome plate modification to the thimble tubes.
No violations or deviations were identified.
Ins ection Fol ow-u Items:
Inspection follow-up items are matters which have been discussed with the licensee involving action on the part of the NRC or the licensee or both.
Inspection follow-up item disclosed during the inspection is discussed in paragraphs 4.b, 5.a. I and 5.a.2.
Unresolved Items Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.
An unresolved 'item disclosed 'during the i'nspection is discussed in paragraph 3.b.
Pectin s and Other Activities:
'a ~
ana erne t Heetin s
(30702)
A meeting was held in the Region III offices on January 19, 1995, to discuss the plans for American Electric Power/Indiana and Michigan Electric to conduct a self assessment of the service water system operational performance at the DC Cook nuclear power plant in lieu of an inspection conducted by the NRC.
A presentation was made to the NRC on the assessment plans and a
handout was provided which included the schedule, licensee and contractor participants, and resumes of the participants as well as other data.
Discussions included the assessment schedule, location of facilities and NRC coverage of the assessment.
b.
Exit Interview (30703)
P I'he inspectors met with the licensee representatives denoted in paragraph I at the conclusion of the inspection on January 30, 1995.
The inspectors summarized the scope and results of the inspection and discussed the likely content of this inspection report.
The licensee acknowledged the information and did not indicate that any information disclosed during the inspection could be considered proprietary in nature.
~l I