IR 05000315/1992002
| ML17329A407 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/06/1992 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17329A406 | List: |
| References | |
| 50-315-92-02, 50-315-92-2, NUDOCS 9203120206 | |
| Download: ML17329A407 (20) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION III
Report Nos.
50-315/92002(DRP);
50-316/92002(DRP)
Docket Nos. 50-315; 50-316 Licensee:
Indiana Hichigan 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 Inspection Conducted:
January 8 through February 18, 1992 Inspectors:
J.
A.
Isom D.
G.
Passehl Rk~ P.
Approved By:
B. L. Jorgensen, Chief Reactor Projects Section 2A Ins ection Summar ate Ins ection from Januar 8 throu h Februar
1992 Re ort Nos.
50-315 92002 DRP '0-316 92002 DRP Areas Ins ected:
Routine unannounced inspection by the resident inspectors of: plant operations; maintenance and surveillance; engineering and technical support; actions on previously *identified items; and reportable events.
Results:
Of the five areas inspected, no violations or deviations were identified in any areas.
The inspection identified notable strength in the investigation into the reactor trip breaker
"B" closure problems.
The inspection disclosed weakness in:
the licensee's boron chemistry control of the refueling water storage tank; in design modification of the emergency diesel generator air start system; and in design of and past measures taken to ensure adequate emergency diesel generator room ventilation airflows.
0 erations:
Unit 1 operated routinely throughout the inspection period.
The licensee commenced shutdown of Unit 2 on January 22, 1992, because of high boron concentration in the refueling water storage tank which could not be restored in the time required by the Technical Specifications.
Relief was granted and the problem resolved in a timely manner without a unit shutdown.
Power was 9203120206 920306 PDR ADOCK 05000315 PDR
lowered to 70 percent on February 1,
1992 because of an irreparable steam line leak at the outlet of the high pressure turbine exhaust piping.
Haintenance and Surveillance:
The licensee continued to have problems with the rel.iability of the emergency diesel generator air start system.
The cause of the Unit 2 reactor trip breaker
"B" closure problems was identified.
En ineerin and Technical Su ort:
The licensee identified a potential.for lower than design emergency diesel generator (EDG) room a'ir. flows which could lead to an abnormally high EDG room temperature.
The initial evaluation determined the condition was not reportable.
However, because the initial evaluation did not consider elevated room temperature effects on other equipment beside the diesel generator, the licensee was performing additional analysis for the past degraded airflow conditions.
Operability of all four EDGs in the past, due to potentially elevated temperatures, is an unresolved ite Detail s Persons Contacted
"A. A.
o'J L.
S.
- K.
R.
- B.
A.
- J.
R.
T.
K.
- G.
A.
"T.
P.
G.
A.
- P.
G.
L.
H.
J.
T.
D.
C.
p.
F.
- H.
L.
L. J.
Blind, Plant Hanager Rutkowski, Assistant Plant Hanager-Technical Support Gibson, Assistant Plant Hanager-Projects Baker, Assistant Plant Hanager-Production Svensson, Executive Staff Assistant Sampson, Operations Superintendent Postlewait, Design Changes Superintendent Weber, Plant Engineering Superintendent Beilman, Haintenance Superintendent Tollas, Acting Safety
& Assessment Superintendent Schoepf, Project Engineering Superintendent Vanginhoven, Site Design Superintendent Wojcik,Chemistry Superintendent Loope, Radiation Protection Supervisor Carteaux, Training Superintendent Horvath, guality Assurance Supervisor Hatthias, Administrative Superintendent 2.
The inspector also contacted a number of other licensee and contract employees and informally interviewed operations, mai ntenance, and technical personnel
.
- Denotes some of the personnel attending the Hanagement Interview on January 24,
1 992.
Plant 0 erat i on s 7 1 707 7 1 7 1 0 42700 The inspector monitored routine facility operating activities in the plant and in the main control rooms.
The inspector reviewed the performance of licensed Reactor Operators and Senior Reactor Operators on procedure use and adherence, record keeping, knowledge of various plant parameters and equipment status, communication and the degree of professionalism in the control room.
The inspector also reviewed the licensee's evaluation, corrective action, and response to off-normal conditions or events.
This included compliance with any reporting requirements.
'a ~
Unit
0 eratin Status:
Unit 1 operated routinely throughout the inspection period at 100 percent power.
Reactor power was reduced to 95 percent on January 23, 1992, to perform planned moderator temperature coefficient testing.
Unit power was restored to 100 percent on January 26, 199 Unit 1 Circulatin Water Pum Motor Failure:
On January 24, 1992, operators observed smoke from the Number
circulating water pump motor.
The motor was deenergized and the smoke was cleared.
The licensee suspected that an upper bearing seal had failed and leaked oil into the motor windings.
There was no evidence of electrical failure and the motor was replaced with an available spare.
Shortly after startup of the replacement motor, a "motor overheated" alarm was received in the control room.
The licensee's followup investigation concluded the motor was running about 2 degrees Centigrade (C) above the alarm setpoint of 120 degrees C.
They decided to run the motor until a
decision is made to replace the motor with another spare or to provide additional cooling.
The failed motor was sent offsite to be rewound.
As a interim solution, the licens'ee has raised the screenhouse door about one foot to improve cooling of the Number 11 circulating water pump with colder air from the outside.
The licensee is pursuing a long term solution involving larger replacement motors for all seven circulating water pumps for both units.
At the end of the inspection report period, the motor temperature alarm had cleared.
Unit 1 Pressurizer Acoustic Valve Monitor Failure:
On January 6,
1992, the Unit 1 pressurizer safety valve acoustic valve monitor (AVM) for valve SV-45A was declared inoperable when it failed its monthly surveillance test,
"Acoustic Valve Position Monitor System Check",
- 12THP 4030.STP.235, Rev.5, June 11, 1990.
The licensee believed the cause of the failure was the charge converter located inside containment.
The licensee was unable to return the monitor to'perable status, and on January 22, 1992,
. requested an amendment to the Unit 1 Tech'nical Specifications (T/Ss) to exempt the monitor from T/S requirements until the end of the current fuel cycle, anticipated to end in June 1992.
The NRC issued the amendment (No.
161)
on February 3, 1992.
Unit 2 0 eratin Status:
Unit 2 began the inspection period at 100 percent power.
Reactor power was reduced to 34 percent on January 24, 1992, to repair (furmanite)
a through wall leak at an elbow on a drain line off the high pressure turbine exhaust piping.
Reactor power was restored to 100 percent on January 27, 1992.
A similar leak developed on another drain line off the turbine high pressure exhaust piping on February 1,
1992.
Reactor power was lowered to 70-percent to investigate and attempt repair, but because of personnel safety concerns, the licensee decided a repair was impractical.
Power was st'abilized at 70 percent to reduce pressure inside the exhaust piping (to about 50 psig)
and to decrease the piping vibration.
The line was scheduled for repair during the refueling outage set to begin February 21, 199 e.'efuelin Water Stora e Tank RWST Hi h Boron Concentration:
On January 22, 1992; the RWST,was declared inoperable per Technical Specifications (T/S) 3. 1.2.8 and 3.5.5, due to the contained borated.water exceeding the maximum boron concentration limit of 2600 ppm.
The RWST boron concentration could not be restored within the one hour T/S time limit.
A reactor shutdown was initiated, and due to the shutdown being required by T/S, an Unusual Event was declared.
Shortly-thereafter, the licensee requested, and was granted, a Temporary Waiver of Compliance from
- T/S 3. 1.2.8 and 3.5.5 by NRC Region III.
The T/S requirement to have the RWST boron concentration between 2400 and 2600 ppm was temporarily waived on a one time basis for 6 days or until the RWST boron concentration was returned to within specifications.,
On January 24, 1992, the'licensee exited the Temporary Waiver of Compliance when boron samples of the RWST showed the RWST to be
.within the T/S limits.
The licensee documented their. request in AEP: NRC: 1172.
No violations; deviations, unresolved or open items were identified.
3.
Maintenance Surveillance 62703 61726 42700 The inspector reviewed maintenance activities to ensure that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with Technical Specifications.
Additionally, the inspector investigated the root cause for these maintenance-related problems to determine whether the licensee h'as adequately addressed the deficiency to prevent future recurrence.
The a.
following activities were inspected:
Diesel Generator Start Failures:
The inspector's review of the continuing diesel generator air start system reliability problems found that the modification performed to correct this situation was deficient.
With the new type of pilot-operated valves installed, the emergency diesel generators (EDG) could not meet their start time requirements.
Based on review of the surveillance test results and discussion with the licensee's staff, the inspector concluded'that there were sufficient differences in operating parameters between the old and new type pilot-operated valves for the licensee to question the appropriateness of the application of the new type pilot-operated valves for the EDG air start system.
The inspector reviewed surveillance test **2 OHP.4030.STP.027AB,
"AB Diesel 'Generator Operability Test (Train B)", Rev.
5, September 14, 1990, performed to verify 2AB Emergency Diesel Generator (EDG) operability.
The EDG failed the test by taking 10.38 seconds to reach rated speed (requirement is less than 10.00 seconds)
and was declared Inoperable on January 13, 1992.
The
licensee's investigation found the cause to be slow operation of POV-1 and POV-2, the pilot operating valves (POVs) for the starting air valves.
These POVs were-recently replaced on all four EDGs as parts for the "old" POVs were no longer available.
After the EDG failure, the licensee contacted the vendor of the
"new" valves (Schrader-Bellows),
who informed the licensee that, although rated for 35-150 psig, the POVs would not operate consistently in the required range at about 40 psig unless cycled one to two times per minute.
However, in the-licensee's application they are cycled about one to two times per month.
This duty-cycle characteristic associated with the new type pilot-operated valve was not included in the vendor literature.
The inspector determined the licensee did not adequately investigate operation of the new type pilot-operated valve near its low pressure limit, nor the difference in the design pressure ranges of the two valve types.
The design pressure of the."old" type valve was25-125 psig.
The vendor indicated that the valves would better meet the licensee's a'pplication at about 55 psig, however, the 55 psig pressure would exceed the requirements of other components in the EDG air start system.
The licensee decided to install the "old" (Hunt-Trimline) valves back into 2AB EDG.
The old POVs were inspected, tested and reinstalled on, January 15, 1992.
The operability surveillance test was successfully performed the following day, and the EDG was returned to operable service within the Technical Specification required time frame.
I A similar event occurred during testing of the Unit
"CD" EDG on-January 26, 1992.
Prior to starting the EDG for its 'monthly surveillance test, operators attempted to roll the EDG on air using the No.
2 air receiver.
The EDG failed to.roll.
Operators then lined up the EDG using the No.
1 air receiver, and the machine started satisfactorily in 8.65 seconds and properly completed the surveillance run and was declared Operable.
The licensee's investigation into the No.
2 air receiver found the associated starting air valve failed to open and admit air to the EDG.
The cause was determined to be failure of the new POV that controls its associated starting air valve.
The EDG was later declared inoperable and the old POVs were reinstalled as with 2AB EDG.
After installation, the machine was successfully tested
'and declared operable on January 27, 1992.
The old POVs were also reinstalled in the remaining two EDGs.
The licensee is pursuing short term and long term plans to address the EDG air start problems.
Since rebuild kits and exact replacement valves are no longer available, they are searching for like valves and parts to use in the short term
.
Long term plans include a redesign of the entire air start system itself.
Unit 2 Reactor Tri Breaker:
The inspector's review of the licensee's investigation into the most recent Unit 2 reactor trip breaker
"8" problems found that the intermittent failure of the undervoltage trip attachment (UVTA) reset arm latch to engage was the most probable cause for the breaker closure problems on August 10 and
and November 16, 1991.
Before the investigation into the latest reactor trip breaker problem, the closure failures associated with the Unit 2 reactor trip breaker
"8" were believed to be caused by a loose terminal screw which secured a wire associated with the shunt trip relay.
Because of the loose terminal screw, it was believed that the wire would intermittently lose contact with the terminal and cause the shunt trip relay 5-RTB to drop out.
Dropping out of the shunt trip relay would cause the breaker to open.
The inspector concluded that the latest investigation into the Unit 2 reactor trip "8" breaker problem was comprehensive and thorough and the initial investigation conducted as result of the August
and August 23, 1991, events lacked the in-depth root cause analysis necessary to prevent this problem from recurring on November 16, 1992.
The initial problems with the Unit 2 reactor trip breaker
"8" were discussed previously in inspection reports 50-315/91017;50-316/91017 and 50-315/91022;50-316/91022.
On November 16, 1991, the licensee experienced problems in closing reactor trip breaker, train "8", during "Instrumentation Checks Prior To Start-Up," procedure
IHP 4030 STP. 180, Revision 5,
November 15, 1990.
Because of the previous problems with this breaker on August 10 and 23, 1991, the licensee performed extensive troubleshooting.
To verify that the problem was with the breaker itself, the licensee verified that there was steady voltage at the input to the reactor trip breaker.
Next, the "A" train breaker was reinstalled into the "8" train breaker cubicle to determine whether the problem could be repeated.
"A" train breaker was verified to work properly.
The reactor trip breaker
"8" was then reinstalled into its cubicle and allowed to warm up for about 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
The breaker was then closed several times and the licensee noted that the breaker picked up the trip bar during these closure attempts,and that there was steady voltage to the undervoltage solenoid.
At this point, because there was steady voltage to the undervoltage solenoids, the licensee believed that the connections and wiring to the undervoltage trip attachment were good and that the problem might be with the under'voltage trip attachment.
To ensure that the breaker cubicle was a possible cause of the "8" breaker closure problems, the "8" breaker was installed into the "A" breaker cubicle, where, after a
1.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> warm-up period,:it began to exhibit similar closure problem On November 18, 1991, the licensee performed troubleshooting on the "B" breaker at the maintenance shop.
During this troubleshooting, the licensee noted.during close examination of the UVTA that the reset arm latch would intermittently fail to engage.
This situation placed the UVTA in a semi-tripped condition in which temperature, vibration or lower voltage to'he undervoltage coil would cause the breaker to trip instantaneously when closed.
Because of the problems with the reset arm to the reactor trip breaker, the licensee continued their investigation and found that the UVTA to the "B" train breaker had been replaced on November 4, 1985.
Additionally, the licensee discovered that the UVTA reset arm calibration had not been performed as recommended by the Westinghouse vendor manual.
The recommendation to calibrate the reset arm first appeared in the 1986 manual revision.
As such, the calibration of the reset arm was apparently not a requirement at the time of the November 4, 1985 UVTA replacement.
The licensee was not able to determine why the reset arm was not calibrated after the Westinghouse vendor manual was revised in 1986.
Because of the numerous problems with the "B" train breaker, a
spare reactor trip breaker was installed in the "B" train cubicle.
After installation of the new breaker, the licensee successfully completed the "Instrumentation Checks Prior To Start-Up" surveillance and the UVTA reset arm was adjusted for proper performance on both the new "B" train and the old "A" train=
breakers on Unit 2.
The licensee plans to check the reset arm adjustment on the remaining Unit 2 bypass breakers and the four Unit 1 reactor trip breakers at the next opportunity.
No violations, deviations, unresolved or open items were identified.
4.
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, and configuration management.
Emer enc Diesel Generator Room Air Ventilation Flows:
The inspector's review of the Emergency Diesel Generator (EDG) ventilation system status found that the EDGs, in the past, may have been inoperable under certain conditions.
In November 1991, the licensee found that EDG room supply ventilation flow could be =insufficient to support long term EDG operation with outside ambient temperature greater than 80 degrees F.
The problem was discovered during pre-installation testing of "tornado dampers" in each EDG room ventilation supply duct.
Previous NRC inspection reports (50-315/91014(DRP);
50-316/91014(DRP)
and 50-315/91022(DRP);
50-316/91022(DRP)).described the events that led to
installation of the tornado dampers and the immediate NRC followup assessments The issue pertained to the licensee's inability to show that certain EDG auxiliaries were designed to sustain the wind loadings and differential pressure associated with the design basis tornado.
The licensee's permanent solution involved installation of a "tornado damper" in each EDG room ventilation supply duct.
Prior to installation of the,tornado dampers, air flow measurements were made to determine the existing air flow capacity of the system.
The EDG and the respective as-found (without damper installed)
and as-left (damper installed) air flow measurement status is noted below.
The as-left values were determined after blade cleaning and pitch adjustments on both the room supply and exhaust fans, which resulted in increased ventilation flows.
EDG No.
As-Found As-Left lAB 35654 cfm
39947-cfm 31434 cfm 42800 cfm 2AB 2CD 34379 cfm 30294 cfm 40867 cfm 40396 cfm The as-found values. for all
EOGs were below the 36000 to 44000 cfm design limit.
In November 1991, the licensee made a preliminary calculation that showed the minimum required supply air flow for the EOG rooms was 29406 cfm based on a maximum outdoor air temperature of 80 degrees Fahrenheit (F).
The licensee decided that until a more detailed analysis was completed, if ambient outside temperatures increase to 80 degrees F.
and remain there for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, any diesel generator with a tornado damper installed would be declared inoperable.
The licensee reasoned that they had until Harch 31; 1992, to complete their analysis, since FSAR Table 2.2-2 showed no occurrence of outdoor ambient temperatures exceeding 80 degrees F.
between November
and Harch 31.'On December 13, 1991, the licensee's corporate office (NS&L) completed their analysis and determined the deficient as-found EDG room ventilation flows were not a reportable occurrence as they calculated 'the EOGs would remain operable with an outside ambient temperature of 137 degrees F.
and an EDG room temperature of 176 degrees F. at a ventilation flow rate of 29406 cfm.
However, NS&L assumed the EDG to be the limiting component and did not account for temperature effects on other equipment in the room needed for the EDG to be operable.
The site Plant Engineering staff rejected that reportability review until NS&L evaluated the effect of elevated EDG room temperature on operability of the attendant equipment (i,e.
instrumentation and motor control centers)
in the EOG room.
The inspector considered the quality of the plant engineering staff's
evaluation to "be a strength.
't the end of the inspection period, the final blade cleaning and pitch adjustments to the EDG room fans to restore all fans to= their design airflow requirements had been completed and the temperature restriction limit on all four EDGs, was in the process of being lifted.
However, the question of the past operability of the EDGs with the as-found ventilation airflow still remained.
Past operability of the EDGs with degraded room ventilation airflows is considered an unresolved item until the licensee completes their analysis.
(Unresolved Item 315/92002-01; 316/92002-01)
No violations, deviations, or open items were identified.
One unr'esolved item was identified involving past operability of emergency diesels during high ambient temperature conditions.
Actions on Previousl Identified Items 92701 92702 (Closed)
Unresolved Item 315/90021-01; 316/90021-01:
As a result of an electrocution event on July 13, 1990, the NRC Human Factors Assessment Branch conducted an investigation on July 26 and 27, 1990, and concluded that the licensee needed to review the electrocution event=
to determine (1) the need for additional controls (validation, signoffs, walkdowns, and verifications) to the clearance request and work review process; (2) the need to incorporate drawings to show the location of plant equipment; and (3) the need for a plant'tandard regarding signs communicating personnel hazards throughout the plant.
Based on the licensee's response
- American Electric Power (AEP) Letter dated December 14, 1990 (AEP:NRC: 1125I) - to Hr.
E.
G. Greenman's letter dated October 3, 1990, this unresolved item is closed.
The inspector noted that the licensee's review of the event found no inherent deficiencies that significantly contributed to the July 13, 1990 electrocution accident.
The licensee's investigation concluded that failure to adhere to the fundamental electrical safety rules applied at Cook Nuclear Plant led to the event and that no additional controls were warranted.
Additionally, the licen'see made changes to the job order process to improve the incorporation of drawings to show the location of plant equipment by adoption of a more formal approach.
Currently, a
pre-job research and briefing is conducted by the lead person and assigned workers before starting a job.
This research and briefing consists of a review of the job scope and'pplicable prints to clarify key clearance points, troubleshooting sequence,'otential pitfalls and circuit operation.
Finally, subsequent to the July event, the licensee has placed additional signs on the switchgear identifying those who are authorized to open the door of the switchgear.
No violations, deviations, unresolved or open items were identified.
Re ortable Events 92700 92720 The inspector reviewed the following Licensee Event Reports (LERs).
The
'eview addressed compliance to reporting requirements and that immediate corrective action and appropriate action to prevent recurrence had been accomplished.
'a ~
b.
(Closed)
LER 315/91001-LL: This LER involved a Roving Fire Watch (FW) which was not upgraded to continuous FW when a pyralarm fire detection zone became inoperable.
On February 25, 1990, a roving FW was in place for an inoperable Unit 1 and Unit 2 Coolant Charging Pump (CCP).room removable wall, and for an inoperable fire door. to the Nuclear Sampling Room.
The FW was not upgraded from a roving to a continuous FW when the fire detection on one
'ide of the wall became inoperable (ref. Technical Specification 3.7.10).
This LER is closed based on the licensee's preventive action and the training given to their operators on the requirements of Technical Specification (T/S) 3.7. 10.
The cause of this event was personnel error.
The involved operators failed to review T/S Open Items to identify inoperable fire rated assemblies within the zone that were required to be upgraded from a roving FW to a continuous FW.
This event was not of major safety significance, since suppression remained available and the roving FW toured the affected areas every half hour.
The preventive action for the event included referencing T/S 3.7. 10 in the Ul and U2 Event Initiated Surveillance procedures.
Plant Manager's Instruction 4031 for Standing Fire Detection Alarms.
In addition, Operators were trained on the T/S 3.7. 10 reference in the procedure and the need to check for inoperable fire barriers when a fire detection zone becomes inoperable.
The Attachments to PMI 4031 were revised and placed into effect on February 27, 1990.
No similar circumstances have occurred to date and this item is closed.,
(Closed)
LER 315/91002-LL:
On March 27, 1990, during a tour of the plant's Turbine Building, an operator found that Technical Specification (T/S) fire doors at the entrance to the Turbine Driven Auxiliary Feedwater Pump (TDAFP) rooms for both units were inoperable because they were blocked open with wooden planks.
Neither door had been declared inoperable at the time the planks were placed. through the entries, as required by T/S 3.'7. 10.
Both doors are normally open, held by fusible links, and would close in case of a fire.
A worker painting the floors of the pump rooms and hallways had placed the planks through the openings to provide access without contact with freshly painted surfaces.
The person erroneously assumed that this was acceptable, as the doors were normally open.
He did not advise the Control Room to have a fire watch posted or take other T/S mandated action.
The condition existed for approximately five hours prior to discovery.
Upon discovery, all
actions required were initiated.
The planks were removed prior to the seven day time limit expiration.
The licensee's corrective action was to counsel both the. individual; who was responsible for the event, and his supervisor on the requirements of T$ S 3.7.
10.'dditionally, the licensee explained.the requirements of T$ S 3.7. 10 to all of the workers.
This event was not repetitive and the LER is considered closed.
'C.
(Open)
LER 316/90008-LL:
On August 7, 1990, with Unit 2 in Mode 6, the licensee identified that samples of the containment divider seal exhibited splitting and longitudinal cracking.
Further, these divider seal material deteriorations were not visible to those performing the inspection because these deficiencies were located on the back side of the seal material.
The licensee could not conclusively determine what caused the divider barrier seal material to degrade in such a manner.
It appeared, however, that only the old type of seal, Uniroyal model number 3807, was affected.
All seals in Unit 2 were replaced with Uniroyal 41-300 seal material, The licensee determined through, laboratory analysis that physical properties such as tensile strength and elongation at break of the 41-300 seal material were far superior to the 3807 material.
Additionally, there was no indication that the previously installed 41-300 seal material had degraded.
The licensee's'orrective action described in the Licensee Event Report (LER) was to replace all divider seal material made of Uniroyal model number 3807, 'in both Units 1 and 2, with the new seal material made of Uniroyal model number 41-300.
The inspector verified through discussion with plant management that the licensee had completed replacement of Unit 1 and 2 divider barrier seal material (see paragraph 4c of Inspection Report 50-315/90022(DRP);50-316/90022 and paragraph 7b of Inspection Report 50-315/90027(DRP);50-316/90027(DRP).
Although the old type of seals have been replaced, the inspector determined that the licensee's corrective action was deficient because the current divider barrier seal inspection procedure,
"Containment Divider Barrier Seal," **12 THP 4030 STP.249, Revision 0, July 20, 1990, still does not require periodic inspection of the seals in those areas which are not visible with the seals installed.
Pending a licensee program to inspect these seal surfaces not visible with the seals installed, or pending some engineering evaluation that the new type of seals will not be sus'ceptible to the problems exhibited by the old seals, this LER will remain open.
No violations, deviations, unresolved or open items were identified.
7.
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 di'sclosed during the inspection is discussed in Paragraph 4.
8.
Nana ement Interview The inspectors
'met with licensee representatives (denoted in Paragraph I) on February 25, 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.
13