IR 05000315/1992012
| ML17329A560 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 07/13/1992 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17329A559 | List: |
| References | |
| 50-315-92-12, 50-316-92-12, NUDOCS 9207170183 | |
| Download: ML17329A560 (21) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos.
50-315/92012(DRP);
50-316/92012(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
and
Inspection At:
Donald C.
Cook Site, Bridgman, MI Inspection Conducted:
Hay 20 thro'ugh June 30, 1992 Inspectors:
J.
D.
E.
K.
J.
D.
W.
A. Isom G. Passehl R. Schweibinz D. Ward Walker Hartland Pegg Approved By:
.
.
nsen, Chief React P
jects Section 2A D
Ins ection Summar
- Inspection from May 20 through June 30,'992 (Report Nos.
50-315/92012(DRP);
50-316/92012(DRP) )
Areas Ins ected:
Routine unannounced inspection by the resident and region-based inspectors of: plant operations; reactor trip; electrical flash accident; maintenance and surveillance; engineering and technical support; actions on previously identified items; reportable events; temporary instructions; and, NRC Region III requests.
Results:
Of the nine areas inspected, no violations or deviations were identified in any areas.
The inspector noted strengths in the conservative management approach to the repair of an RHR valve and in the operator's control of Unit 2 during a
=-
reduced inventory evolution.
Additionally, the inspector's observations of control room activities during the initial roll of the Unit 2 main turbine identified strengths in the operator's response to a failure of a feedwater
regulating valve which caused some difficulty in maintaining the proper water level in the steam generator.
The inspector also noted a strength in.the quality the Plant Engineering Department's investigation and repair of the Unit 2 Acoustic Valve Monitors.
9207170183 920706 PDR ADOCK 05000315
Areas for improvement were identified in the operations area during the Unit 2 i educed inventory evolution which involved the quality of operator review of industry events during pre-shift briefings and lack of detailed understanding of hydraulic conditions during system drain dow DETAILS Persons Contacted
'a ~
Mana ement Heetin
- June
1992 merican Electric Power Service Com an AEPSC D.
H. Williams, Senior Executive Vice President E.
E. Fitzpatrick, Vice President, Nuclear Operations, S. J.
Brewer, Manager, Nuclear Safety and Licensing P.
A. Barrett, Director, guality Assurance D.
H. Halin, Section Manager, Nuclear Licensing l
Indiana Michi an Power Cook Nuclear Power Plant A. A. Blind, Plant Manager R.
F. Kroeger, Manager, Nuclear Plans and Programs H.
E. Barfelz, Senior Engineer-Safety
& Assessment
'uclear Re ulator Commission NRC b.
A. B. Davis, Regional Administrator C. J. Paperiello, Deputy Regional Admi'nistrator, RIII E., G.
Greenman, Director, Division of Reactor Projects B. L. Jorgensen, Chief, Projects Section 2A, RIII J.
A. Isom, Senior Resident Inspector, RIII Ins ection - Ma 29 throu h June
1992 A. A. Blind, Plant Manager
- J.
E. Rutkowski, Assistant Plant Manager-Technical Support L. S. Gibson, Assistant Plant Manager-Projects K.
R. Baker, Assistant Plant Hanager-Production B. A. Svensson, Executive Staff Assistant J.
R.
Sampson, Operations Superintendent
- T. K. Postlewait, Design Changes Superintendent
- G. A. Weber, Plant Engineering Superintendent
- T. P. Beilman, Maintenance Superintendent
- G. A. Tollas, Acting Safety
& Assessment Superintendent P.
G. Schoepf, Project Engineering Superintendent L. H. Vanginhoven, Site Design Superintendent J.
T. Wojcik,Chemistry Superintendent D.
C.
Loope, Radiation Protection Supervisor P.
F. Carteaux, Training Superintendent L. J. Matthias, Administrative Superintendent
- J. H. Kaufmann-, Construction Mana'ger
- R. S.
Ptacek, Safety and Assessment Administrative
Compliance Coordinator
- S.
R.
Gane, Site gA/gA auditor
- H. J.
Gumns, Safety and Assessment Administrative Compliance Coordinator
- R. T. Rickmann, Hanagerial Staff
- D. H. Fitzgerald, General Supervisor Chemistry and Environmental 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 Hanagement Interview on July 1, 1992.
Plant 0 erations 71707 71710 42700 The inspector observed routine facility operating activities as conducted in the plant and from the main control rooms.
The, inspector.
monitored the performance of licensed Reactor Operators and Senior Reactor Operators, of Shift Technical Advisors, and of Auxiliary Equipment Operators including procedure use and adherence, records and logs, communications, and the degree of professionalism of control room activities.
The inspector reviewed the licensee's evaluation of corrective action and response to off-normal conditions.
This included compliance with any reporting. requirements.
The inspector noted the following with regard to the operation of Units 1 and 2 during this reporting period:
a.
Unit
Summar Of 0 eration b.
Unit 1 began this inspection period at 69 percent power, with an end of. cycle 12 coastdown in progress for a scheduled refueling outage.
=-The unit operated routinely throughout most of the inspection period.
The reactor tripped from HODE 3 during shutdown for the refueling outage on June 22, 1992.
The reactor trip was caused by a source range high flux reactor trip signal that was generated when both source range detectors failed high.
At the time of shutdown the unit had been running for a record 277 days.
The estimated duration of the outage is 93'days.
Unit 2 Summar of 0 eration Unit 2 began this inspection period in HODE 5, continuing with the cycle 8-9 refueling outage that began February 22,, 1992. 'n June 16, 1992, the reactor was taken critical following a 116 day refuel,ing outage, The licensee placed the unit in HODE 1 at
percent reactor power early on June 19, 1992, for main turbine testing.
Excessive bearing vibration was observed during the initial roll of the turbine, and the reactor was placed back into
HODE 2 to investigate.
During the shutdown into HODE 2, operators noted that the feedwater regulating valve for the No.
4 steam generator (2-FRV-240) was sticking such that'he steam generator water level could not be properly maintained.
Operators managed to maintain proper level by use of the steam generator blowdown valves, until the normal feedwater system could be isolated and the auxiliary feedwater system placed in service.
The response by the operators in maintaining steam generator water level within their required range with a stuck open feed regulating valve was considered a strength.
Throughout the week following criticality, the licensee made several unsuccessful attempts to balance the turbine by placing weights on various sections of the rotor.
The unit ended the inspection period with preparations underway to parallel the main generator to the grid after several more attempts to balance the rotor.
Other emergent work items which appeared near the end of the refueling outage that caused or contributed to postponement of the scheduled startup date were as follows:
The seals on No.
23 Reactor Coolant Pump were reworked after seal leakoff was measured at 17-20 gpm.
In addition, the lower radial bearing support ring had become loose during the
"bump" of the pump which necessitated additional repair time.
The hydraulic actuator on the No.
3 steam generator stop valve was replaced after it would not hydraulically open or close during testing in HODE 3.
A shop rag was found in one of the oil ports of a solenoid valve in the actuator.
The licensee believed the rag was left in the actuator at the Atwood/Horrill vendor repair facility where it had been sent for refurbishment.
A Residual Heat Removal System (RHR) isolation valve (2-ICH-321)
was rebuilt when the stem and backseat were found damaged during a job to replace the packing.
Unit 2 Reduced Inventor 0 eration The inspector reviewed the Operations Department preparation for and drain down to near mid-'loop operations.
The mid-loop operation was required to support the repair to Unit 2 RCP seal package which was found to be leaking excessively.
The inspector also observed the following:
Pre-shift briefs for each crew prior to going on shift.
This included training on the drain down process and a
review of industry events surrounding this proces Preparation for the drain down process, including review of procedure scheduling of plant work, and ensuring proper management coverage during drain down.
Actual drain down of the system to a reduced inventory condition.
As a result of these reviews and observations, the following strengths were noted:
A daily bri'efing of plant management on the status helped to enhance the process and limit unnecessary activities within the plant.
Unrelated activities within the control room were kept to a minimum, allowing the crew to maintain a positive control on the drain down process, Pre-shift training insured that the oncoming crew understood the process, In all cases observed, the supervisor kept the crew informed of what was going on and prevented unnecessary activities from starting.
The following were observed as areas where improvements could be made:
On two occasions during pre-shift briefings, industry events were only mentioned with no effort to review the event in detail to learn from them.
Although the administrative procedure for outage activities contained comments and cautions in preventing activities outside the control room from affecting the drain down process, the operational procedure used for reduced inventory operation lacked some of these caution statements.
The crew demonstrated a lack of complete understanding of the effects of trying to drain down a system that had not been filled and vented.
Unexpected hydraulic effects were noted which required the system to be drained a number of times prior to actually achieving the desired level.
Air pockets in the steam generators caused them to act like accumulators.
Each time the system was drained down and the pressurizer relief tank pressure vented off, the system would partially refill from the inventory in the steam generators.
The drain down schedule was unexpectedly prolonge Overall, the facility performed the process of draining down to a
r'educed inventory in a safe and controlled manner.
d.
Unit 2 Power Escalation Observations The inspector observed power escalation into HODE 1 durin'g the early morning on June 19, 1992, as the licensee was preparing the main turbine for its initial roll.
Senior licensee management was also present.
The inspector saw that control room activities were performed in a controlled, orderly, and professional manner.
The inspector followed the evolution using the procedure entitled
"Power Escalation",
- 2 OHP 4021 001.006, Rev. 14, Hay 3, 1991, and noted that reactor power escalation and primary and secondary heatup limitations were adhered to.
Communications between the operators monitoring the reactor and those monitoring the secondary plant were good.
No violations, deviations, unresolved or open items were identified.
3.
Reactor Tri 93702 4,
On June 22, 1992, Unit 1 tripped from HODE 3 during the shutdown for its refueling outage.
The trip was caused by a source range high flux reactor trip signal that was generated when both source range detectors N-31 and N-32 failed when they were energized during shutdown.
The reactor trip setpoint was 100,000 counts per, second (cps).
Instrument N-32 failed high at 1,000,000 cps, and instrument N-31 cycled erratically between approximately 100 and 100,000 cps.
At the time of the trip, the reactor was subcritical with 3 of 4 control rod banks fully inserted; the fourth was inserting with 85 steps remaining.
The trip released the remaining control rods and all shutdown rods into the core.
Both wide-range source. range detectors N-21 and N-23 indicated decreasing flux levels immediately following the trip.
The licensee began borating the system to maintain shutdown margin in accordance with Technical Specifications.
The licensee's investigation of the trip has thus far attributed the malfunction of N-31 to be with the detector, and the malfunction of N-32 to be either the connection at the detector or the detector itself.
The'nstrument and Control staff replaced both source and intermediate range detectors on June 27, 1992.
No violations, deviations, unresolved or open items were identified.
Electrical Flash Accident 92701 The inspector reviewed the April 30, 1992, electrical flash accident that caused a flash burn and other injuries to a licensee contract painter from a 34.5kV source feeding the Unit 2 Reserve Auxiliary Transformer No.
201AB.
The painter drew the electrical arc while painting fireheader piping from the framework above the transformer.
The event was reviewed to determine the effectiveness of the program the
licensee has in place to'revent electrical-related personnel accidents.
The inspector interviewed members of the licensee's staff who investigated the accident and examined the procedure for writing clearances, entitled "Clearance Permit System",
PMI-2110, Rev. 18, August 9,
1991, to determine whether there were adequate controls for properly isolating equipment for personnel safety during work on the equipment.
The inspector concluded that the licensee's program was adequate but could be enhanced to insure that personnel knowledgeabl'e in the right engineering discipline would write and review clearance requests.
The inspector reviewed the clearance permit procedure to determine the qualifications of those persons who can initiate and approve clearance permit requests.
The procedure required that
"A person with a full understanding of the activity to be performed shall provide information for the Clearance Permit Request and ensure only accurate and complete information is supplied."
In this case, the inspector found that the individual who wrote the Clearance Request was an Indiana and Michigan (I&H) Construction civil field engineer who was not knowledgeable in reading electrical diagrams.
The person correctly requested that the transformer needed to be tagged out for painting fireheader piping in the area, but failed to realize that the 34.5kV feed also needed to be isolated because of the proximity of this high voltage source near the work location.
Moreover, the supervisor of the clearance request writer, also a Construction civil field engineer, mi'ssed the requirement to isolate the high-voltage source during his review.
The inspector reviewed the procedure for writing the actual clearance from the clearance permit request to determine whether the clearance.
writers from the Operations staff, termed the CCG (Central Clearance Group),
could have recognized the inadequate clearance request..
The inspector determined that based on the information the CCG was given by the clearance initiator,-the CCG group could not have recognized that the clearance requested might cause hazardous working conditions.
The inspector found that a second review of the clearance request was performed by the CCG, and the inadequate clearance request was not caught during this review.
The clearance procedure stated that "two members of the Operations Department are required to ensure that the existing or proposed boundaries are adequate for each clearance permi.t request".
The licensee's stated practice was that the persons who write the clearance permit request were responsible to specify the equipment and energy sources that need be removed, e.g.,
system depressurized, incoming line deenergized, etc.;
and it was the responsibility of the CCG group to determine how and where to set the boundaries around the equipment, whether by opening circuit breakers, pulling fuses, aligning valves, etc.
The licensee interpreted the above requirement to mean that the CCG's job was to verify that the boundaries were acceptable for the work identified.
In this case, the CCG determined that the clearance'permit request was adequate as written by the civil group for de-energizing the transforme The inspector interviewed members of the licensee's investigative staff and reviewed their investigation report to determine why the live 34.5kV source went unnoticed by personnel in the field.
The inspector learned that two days before the accident, a prejob briefing was held between an I&M electrical superintendent and the foreman responsible for the painting work to discuss the fireheader painting activity around the transformer.
The I&M electrical superintendent and the foreman walked out to the transformer, without the clearance paperwork, and noticed three sets of ground straps one of which was on the 34.5kV feed to the disconnect indicating that the"line at this time was deenergized.
The I&M electrical superintendent erroneously assumed this ground was part of the clearance for the fireheader painting work being discussed.
In fact, the ground was present for a separate, broader clearance for an activity by the St. Joseph electrical group.
The inspector concluded that the painters and supervisors failed to recognize the change in. the grounded condition of the 34.5KV feed to the transformer when the clearance for the St.
Joseph group was removed.
The inspector found the licensee's actions to prevent recurrence of this event to be satisfactory.
The clearance permit procedure was changed to require a more complete description of work to be done, the conditions needed to perform the work, and the specific tag points when clearances are requested.
It now requires that personnel submitting clearance requests be knowledgeable in the discipline associated with the work activity and the equipment to be cleared.
In addition, the clearance request initiator can no longer sign for the responsible department supervisory review on the clearance request.
No violations, deviations, unresolved or open items were identified.
Maintenance Surveillance 62703 '1726 42700 The inspector reviewed maintenance activities as detailed below.
The focus of the inspection was to assure the maintenance activities 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 thi.s 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.
RHR Motor 0 crated Isolation Valve Leak 62703 During post maintenance testing, it was observed that the stainless steel, Class 2, isolation valve No. 2-ICM-321 had an excessive packing leak.
The valve was stroked several times and the packing was re-torqued, but the leak off rate at the packing gland did not decreas The maintenance department disassembled and visually examined (VT)
the 8" gate valve.
It was found that the backseat surface of the bonnet had a small pie shape chip removed and that the stem bore of the bonnet and the stem were scoured.
Liquid penetrant examination (PT) of the stem bore and the. back seat surface found several small cracks.
The cracks were ground out and a welding repair was initiated.
The repair welding resulted in additional cracking because the hardfaced backseat material, stellite, had not been completely. removed.
A decision was made to enlarge the stem bore by machining to remove all stellite and cracks, After machining, the area was examined using liquid penetrant test, found to be acceptable and built up with new weld metal.
The bonnet was then machined to have a stem bore of the original size, examined using liquid penetrant testing and found to be acceptable.
The valve was then reassembled, tested, and put into service.
A new bonnet with a stellite backseat surface may be installed at the next refueling outage or shutdown of a sufficient duration.
The NRC inspector observed liquid penetrant examinations and grinding of cracks.
The inspector also reviewed the repair traveler, drawings, procedures and other NDE and welding documentation.
The repair was found to be acceptable and in accordance with ASME Code requirements.
Plant 250 Volt DC S stem Proceudre Review The inspector performed a limited review of the 250 volt dc electrical system and related sections of the Final Safety Analysis Report (FSAR), Technical Specifications (TS),
and Institute of Electrical and Electronic Engineers (IEEE) standards to assess the adequacy of surveillance procedures related to the plant batteries.
The inspector found the procedures to be adequate in that the surveillance procedures addressed all TS requirements.
The inspector reviewed the following surveillances as part of the above evaluation:
1)
AB, CD, AND N-TRAIN BATTERY WEEKLY SURVEILLANCE AND MAINTENANCE, **12IHP4030.STP.600, Rev.O, December 19, 1990 2)
AB, CD, AND N-TRAIN BATTERY QUARTERLY SURVEILLANCE AND MAINTENANCE, **12IHP4030.STP.601, Rev.O, August 29, 1991 3)
AB, CD, AND N-TRAIN BATTERY AND CHARGER SERVICE OR PERFORMANCE TEST, **12IHP4030.STP.602, Rev.O, December 31, 1991 4)
BATTERY CELL REPLACEMENT, **12IHP5021.EMP.006, Rev.O, April 25, 1991
5)
BATTERY CONNECTION MAINTENANCE, **12IHP5021. EMP.008, Rev.O, April 12, 1991 c.
Unit 2 Hain Steam Sto Valve Failure to H draulicall 0 crate Due to Sho Ra in Actuator The inspector reviewed an operational problem with the hydraulic
'actuator installed on the Main Steam Isolation Valve (HSIV) for the Unit 2 No.
3 Steam Generator (2-HRV-230), after a shop rag was found in the actuator during MODE 3 startup testing.
The actuators were sent offsite to Atwood/Morrill for refurbishment during the recent Unit 2 refueling outage.
The licensee found that the rag was left in the cylinder of the actuator during this refurbishment, and eventually broke up and worked its way out of the cylinder and into the hydraulic lines.
A new spare actuator was subsequently installed and tested satisfactory.
The faulty actuator was sent back to Atwood/Horrill for cleaning and rebuild.
The inspector reviewed the event to determine whether the licensee's receipt inspection process should have found the shop rag, and what post-installation testing was performed that could have identified the presence of the rag prior to MODE 3 startup testing.
The inspector's review of the receipt inspection process found that a detailed receipt inspection was not performed and it was not required.
The actuato'r was classified as a, "standard-grade" component.
For these types of components the licensee performs a
visual inspection to verify nothing obviously broken or missing, and verifies part numbers and quantity.
The licensee typically does not do an internal inspection of standard components, and in this case it would have. required disassembly of the newly rebuilt actuator to find the shop rag.
The inspector's review of the post-installation testing found that the actuator was cycled several times immediately after installation in May 1992, and that the presence of the shop rag was not identified until MODE 3 startup testing.
The inspector's review of the actuator installation procedure, entitled "Hain Steam Stop Valve Maintenance",
Rev.4, June 28, 1991, found that after the actuator was coupled onto the stem of the valve and hydraulic fluid was added, the valve was "cold" stroked several times, as documented on Job Order C3919, and various fittings were inspected for hydraulic fluid leakage and some were tightened.
Maintenance mechanics observed no evidence of maloperation with the hydraulic actuator at this time.
On June 14, 1992, 2-MRV-230 passed two fast closure tests with times of 3.41 and 3.42 seconds.
The required ISI time limit is 3.5 seconds or less.
During the opening of 2-HRV-230 after the second test, the hydraulic actuator stalled and the licensee's subsequent inspection found pieces of the shop rag that the licensee believes was thrust through the actuator during the fast closure tests.
No violations, deviations, unresolved or open items were identified.
En ineerin and Technical Su ort 37828 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.
Unit 2 Pressur'izer Acoustic Valve Monitors The inspector reviewed an operability issue regarding the Acoustic Valve Monitor (AVH) for Unit 2 Pressurizer Safety Valve 2-SV-45C.
The AVH was declared INOPERABLE on November 30, 1991, following performance of the scheduled monthly channel check surveillance test, due to spurious alarm indications.
The NRC granted, the licensee a Technical Specification (TS)'xemption to prevent shutdown of the unit when the associated
day TS Limiting Condition for Operation would have been exceeded.
The licensee identified the likely source of the spurious alarms as the charge converter located inside containment.
At that time, access to the charge converter was prohibited because of environmental and radiation hazards.
The licensee's investigation during the recent Unit 2 refueling outage was thorough, with good root cause analysis.
The licensee found the AVH to have a failed charge converter and accelerometer.
Both the charge converter and accelerometer, as well as the cable assembly, were replaced.
System calibration and calibration checks were then successfully performed and the AVH system was returned to operable status.
The licensee indicated the signal cable may have become disconnected while workers were inside the pressurizer doghouse during a short outage when Unit 2 tripped on November 15, 1991, and remained off line until November 20, 1991.
The workers may have unknowingly broken the signal
"-'able for the PORV AVH.
The inspector reviewed the preventive maintenance (PH) requirements to determine future reliability of the AVHs and found them to be satisfactory.
The PH is outlined in the AVH calibration procedure entitled "Acoustic Valve Monitor System Test", **12 THP 4030 STP.234, Rev.
9, July 3, 1990, which is required by Technical Specifications to be performed every refueling outage.
The procedure requires trending of AVH performance to determine remaining qualified life of the AVH components.
The procedure states in the
"Recommended Maintenance and Surveillance" section that the charge converters and cable assemblies for the AVHs be replaced prior to exceeding their qualified lifetime.
Those times are listed as 2.92 years (Unit 1)
and 10.58 years (Unit 2)
for charge converters, and 5.58 years (Unit 1)
and 27.33 years (Unit 2)
for cable assemblies.
The longer lifetimes in Unit 2 are based on a
lower average ambient temperature.
The accelerometers are qualified for 40 years in both units.
Although not stated in the procedure, the licensee stated they plan to replace the accelerometers and charge converters in Unit 1 every refueling outage, and are evaluating whether to replace those components in Unit 2 at the same frequency or during every other refueling outage, as is the current practice.
No violations, deviations, unresolved or open items were identified.
Actions on Previousl Identified Items 92701 92702 a.
Closed Violation 50-316 90022-01A 50-316 90022-01B 50-316 90022-01C: Maintenance Performed on Safet Related E ui ment Without Use of Procedures The inspector identified several examples of maintenance performed, on safety related equipment without use of procedures.
In one case, an incorrect number of packing rings were installed on the Unit 2 North Safety Injection Pump because the mechanic used only the diagram of the.seal assembly to determine the correct number of packing rings to be installed.
In the second example, repair to the actuator of a pressurizer power-operated relief valve was completed without a procedure, and repair to the actuator of another pressurizer power-operated relief valve was performed without the use of a procedure reviewed by the Plant Nuclear Safety Review Committee (PNSRC)
and approved by the Plant Manager.
The inspector found the licensee's corrective action for this violation to be acceptable.
The licensee responded to the violation by developing a "Procedure Requirement Determination Checklist," to determine when a specific procedure is requir'ed to perform repairs.
The standards and methodology to be used in this determination were formalized in procedure
"Maintenance Planning,"
HAP 3.3-05, April 30, 1992, Revision 2.
Additionally, a
memorandum was issued to all department planners on January 30, 1992 requiring that the checklist be used for all safety-related work packages planned by the Maintenance Department" after February 1,
1992.
In accordance with the new Maintenance department policy, all "safety-related work packages planned by the Maintenance Department after February 1,
1992 which do not specifically call out an approved procedure, shall contain an Action Request evaluation documenting the reason a procedure is not being used.
The planner would identify any documents required to perform the activity using attachment 6,
"Document Usage Guide,", to the
"Maintenance Planning" procedure.
As part of this review, 'the planner would utilize the "Procedure Requirement Determination Checklist" when work on a safety-related component will be performed for which an approved procedure is not available.
b.
Closed Violation 50-315 91010-01:
Inade uate Post-Maintenance Testin on the Unit 1 Chemical and Volume Control S stem Cross-Tie Valve 1-CS-536 C.
The inspector found the licensee's corrective action to address a
lack of post-maintenance testing performed on a Unit 1 Chemical and Volume Control System Cross-Tie Valve to be satisfactory.
The inspector found that because the body-to-bonnet region was never pressurized after the valve was disassembled and repaired, the valve developed an unacceptable leak during Unit 1 operation.
The licensee corrective action was to identify the documents used to determine the various testing requirements as attachment 7 to procedure
"Maintenance Planning,"
HAP HA3.3-05, April 30, 1992, Revision 2 for planner's use.
Closed 0 en Item 50-316 89009-01:
Containment S ra Pum test s ecifies narrower um recirc flow than can be verified usin the existin au e
As noted in NRC Inspection Report 50-316/91014, Paragraph 6.h, this item remained open at that time pending the completion of minor modifications to bring the plant in compliance with Engineering Control Package (ECP) 1/2-I2-03.
These modifications included the replacement of the bellows with a unit having a
differential pressure range of 0-300 inches of water and a 0-1170 GPH square root scale (I.R. 50-316/91014 incorrectly states a "0-1700 GPH square root scale" ).
The inspector verified that these modifications were completed and this item is closed.
No violations, deviations, unresolved or open items were identified.
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 LER 315 90012-LL: Failure to Com l with Plant Technical S ecifications when Fire Watch Postin Re uirements were Hiscommunicated On October 15, 1990, and again on October 20, 1990, Technical Specification (TS) required fire watch tours were missed due to verbal miscommunication.
The first occurrence involved the incorrect positioning of a fire watch after a sprinkler system was removed from service, which was required by TS 3.7.9.2.
The second event involved the failure to perform a turbine building fire protection tour, required by TS 3.7. 10, due to several inoperable fire barriers.
The cause of each event was personnel error.
In each case, the establishment of the fire watch was not performed due to a
misunderstanding of verbal communications.
Upon discovery of each occurrence, immediate corrective action was taken to establish the required fire watches.
The contractor involved took appropriate administrative action and conducted pre-shift briefings to stress the importance of clear and concise oral communications.
Safety significance of the missed fire watches was minimal.
To date there have been no'imilar recurrences; this item is closed.
No violations, deviations, unresolved or open items were identified.
Tem orar Instructions Licensee Evaluation of Chan es to the Environs Around Licensed Reactor Facilities TI 2515 112 The objective of this Temporary Instruction was to determine if the licensee has adequate programs to evaluate public health and safety issues resulting from changes in population distribution or in industrial, military, or transportation hazards that could arise on or near the site.
The inspector conducted the review in accordance with the guidelines provided in TI 2515/112, and found that while the licensee has no formal program, they have several methods in which they inform the NRC of changes in the environs, The most prominent of these is the Annual Radiological Environmental Operating Report.'ther methods include Licensee Event Reports (LERs)
and responses to various NRC requests for information.
The inspector also conducted a vehicle tour of the site and a limited tour of the local area surrounding the site, reviewed a
Draft Evacuation Time Estimate Report for the D.
C.
Cook Emergency Planning Zone (EPS),
and did an independent verification of some of the data in the report.
The licensee agreed to evaluate, one of the observations made by the inspector during his tour of the site.
It involved the placement of concrete barricades to block access North to and from Thornton Drive from the main entr'ance area just West of the bridge across Interstate 94.
These barricades were put in place on April 1 or April 2, 1991, to prevent a potential traffic safety problem.
The inspector's concern was that in the event of an evacuation, an accident on the bridge would close off an egress route without any easy alternative.
The licensee decided to change the type of barricade to one that could be easily moved if necessary.
In response to the inspectors questions on updates to the FSAR regarding those items described in 03.01.'b.
1 through 03.01.b.9 of TI 2515/112 the licensee committed that:
(1)
For those items where additional information has already been sent
,to the NRC, the FSAR will be updated in 1993 to be consistent with those submittal (2)
,(3)
For the remaining items, the licensee will initiate actions to determine whether additional updating is required.
The 1993 FSAR update will incorporate the results of this effort.
In the interim, if significant changes occur or are discovered which warrant NRC notification, the NRC will be notified in a
separate submittal.
This TI is considered closed.
Any additional questions will be addressed by separate correspondence.
No violations, deviations, unresolved or open items were identified.
10.
Re ion III Re uests 92705 Closed AMS No. RIII-92-A-006 Concern Steam line internal vanes may have been improperly repaired and the pipe wall is eroded and thin. If the vanes break loose, the isolation valve might be damaged.
'a ~
NRC Review The NRC inspector reviewed the Job Order, drawings, and weld data package and other welding and nondestructive examination (NDE)
documentation covering inspections and repairs of the turbine cross under piping.
The licensee's inspection program has required an inspection every refueling outage of the four pipes, scoops, and vanes on both units since 1980, due to erosion potential associated with this piping.
The repairs performed this outage consisted of weld repairing the following components with E-7018 and E-309-16 weld material and A36 carbon steel plate material:
(1)'our 60"-68" cone shape, 1/2
" thick, A-36 carbon steel (c/s) pipes.
I (2)
Four c/s steam scoops.
(3)
Several c/s turning vanes.
(4)
One c/s steam scoop support leg welded to the pipe.
The turning vanes are welded into the steam scoops which are supported by legs inside of the piping.
The vanes, scoops and pipes are part of the main steam, nonsafety related, ANSI 831. 1, 1967 Edition, cross-under piping.
The welders performing the repairs were qualified/certifi.ed in
.accordance with ASHE Section IX and the personnel performing visual (VT) and ultrasonic thickness examinations (UT) were qualified/certified to SNT-TC-1A.
Licensee personnel performed inspection of the fit-ups on the 3/16" plates on the steam scoops and VT on the pipes, scoops, and vanes.
An outside contractor performed. the UT on the pipes.
b.
Conclusion This concern was not substantiated in that the welders, gC and NDE personnel were properly qualified and all related documentation was found to be acceptable.
The licensee has an aggressive inspection program for this piping and repairs are made as required.
The wall thinning stated in this concern was found.to refer to the internal scoop assembly and not the pressure boundary piping.
As such, there is little safety significance associated with this concern.
The scoops and not the steam piping may be replaced during a future outage.
With respect to the vanes breaking loose, the pieces would have to travel through the
'moisture separator drain tank or the moisture separator as well as the associated strainer before reaching any valves.
This is considered to be a highly unlikely event.
No violations, deviations, unresolved, or open items were identified.
11.
Mana ement Meetin A management meeting, attended as indicated in Paragraph 1b, was conducted at the NRC Region III office on June 2,
1992.
The purpose of the meeting was to discuss licensee.
1992 goals and objectives',
plant performance trending,
"graded" root cause investigation, achieving
'ffective communications, and licensee industry involvement initiatives.
Formal presentations were made on most topics, the licensee responded to numerous NRC questions, and various informal discussions on the above and related topics occurred.
12.
Mana ement Interview The inspectors met with licensee representatives denoted in Paragraph 1b on July 1, 1992, 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 or processes as proprietary.
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