IR 05000327/1993052
| ML20059B464 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 12/23/1993 |
| From: | Holland W, Kellogg P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20059B448 | List: |
| References | |
| 50-327-93-52, 50-328-93-52, NUDOCS 9401040156 | |
| Download: ML20059B464 (23) | |
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UMITED STATES
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k NUCLEAR REGULATORY COMMISSION REGION il
.c S W1 MARIETTA STREET, N.W., SUITE 2900
% E ATLANTA, GEORGIA 303234193 o
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Report Nos.: 50-327/93-52 and 50-328/93-52 Licensee: Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Docket Nos.: 50-327 and 50-328 License Nos.: DPR-77 and DPR-79 Facility Name: Sequoyah Units 1 and 2 Inspection Conducted: vember 7 through December 4, 1993 Lead Inspector: ! / / 46 W. E/' Hollin i;Nniorgsidgnt Inspector
/2]?s /45 Date Sisned Inspectors: S. M.'Shaeffer, Resident Inspector B. R. Crowley, Reactor Inspector J. L. Shackelford, Reactor Inspector S. E. Sparks, Project Engineer R. D. Starkey, Resident Inspector L. Trocine, Resident Inspector Approved by: / ,
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y, /7/77/13 Paul /J. KglJoggg@4ef 744Fction_4A Date Signed >
Division"bTR tor Projfcts
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SUMMARY Scope:
Routine resident inspection was conducted on site in the areas of plant operations, plant maintenance, plant surveillance, evaluation of licensee self-assessment capability, licensee event report closecut, and followup on previous inspection findings. During the performance of this inspection, the resident inspectors conducted several reviews of the licensee's backshift or weekend operation PDR ADOCK 05000327 ,
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Results:
In the area of Operations, operator response to two Unit 2 transients involving a charging system event and a Unit 2 reactor trip were good (paragraph 3.a).
In the area of Engineering, a review of problems involving check valve operation in the component cooling system resulted in a conclusion that the licensee's program for review of potential generic issues continues to be weak. Although immediate management focus on Unit 2 safety was appropriate after identification of the Unit 1 problem, and Unit 2 was shut down for corrective actions, more aggressive technical review of past problems could have resulted in inspections prior to Unit 2 restart. This area needs continuing management attention (paragraph 4.a).
In the area of Engineering, a non-cited violation was identified due to an inadequate Individual Data Package (IDP) being utilized to set two air regulators for charging system flow control valves. The IDP was inadequate due to incorrect vendor manual information (paragraph 4.b).
In the area of Engineering, a weakness was identified regarding the over-ranging of air regulators beyond their design output (paragraph 4.b).
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In the area of Engineering, examples were identified whera engineering personnel did not describe and/or document justifications for actions in a clear and concise manner (paragraph 6).
In the area of Maintenance, a violation was identified regarding an inadequate surveillance procedure for inspection of the steel containment pressure vessel (paragraph 8).
In the area of Operations, a review of cold weather preparations including procedure reviews, review of outstanding items on the " Freeze Protection Report," and walkdowns of selected freeze protection equipment, allowed for a conclusion that the licensee is implementing an adequate program for the protection of critical components during extreme cold weather conditions (paragraph 9).
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REPORT DETAILS Persons Contacted
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Licensee Employees
- R. Fenech, Site Vice President !
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- D. Keuter, Vice President, Nuclear Readiness K. Powers, Plant Manager J. Baumstark, Operations Manager L. Bryant, Maintenance Manager 3
- M. Burzynski, Nuclear Engineering Manager ;
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- M. Cooper, Maintenance Program Manager
- D. Driscoll, Site Quality Assurance Manager
- T. Flippo, Site Support Manager ;
C. Kent, Chemistry and Radiological Control Manager l D. Lundy, Technical Support Manager .
R. Rausch, Site Planning and Scheduling Manager
- J. Symonds, Acting Modifications Manager R. Shell, Site Licensing Manager -
J. Smith, Regulatory Licensing Manager
- R. Thompson, Compliance Licensing Manager
- J. Ward, Engineering and Modifications Manager
- N. Welch, Operations Superintendent NRC Employees R. Crienjak, Chief, DRP Branch 4 .!
P. Kellogg, Chief, DRP-Section 4A !
- W. Holland, Senior Resident Inspector .;
- S. Shaeffer, Resident Inspector _
- Attended exit intervie Other licensee employees contacted included control room operators, shift technical advisors, shift supervisors and other plant personne Acronyms and initialisms used in this report are listed in the last paragrap . Plant Status Unit 1 began the inspection period in MODE 5 (day 216 of the Cycle 6 .
refueling outage). At the end of the inspection period Unit I remained 4 in MODE 5 with efforts continuing to correct restart deficiencie l Unit 2 began the inspection period in power operation. The unit operated at approximately 40% power until November 8, 1993, when the generator was taken off the grid to make repairs to the generator <
voltage regulator. Repairs were completed on November 10 and the unit
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Il returned to pour operatio Full power was reached on November 12. On j November 16, the unit was shut down and cooled down to approximately ;
225 'F (MODE 4) due to concerns associated with the potential j operability of eight component cooling water system (CCS)' check valves !
located in the supply lines to the RCP thermal barrier heat exchanger !
This issue was first identified on the same valves in Unit I and .
involved the failing of the valves in the open position due to corrosion j product buildup. Subsequent repairs to the valves were made with the l unit in MODE 4 along with other forced outage activities including l troubleshooting of the main generator voltage regulator alarm circuitry ;
problars. The unit was taken critical on November 22 and returned to (
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power operation on November 23, 1993. During power escalation a leak l was observed on a spoolpiece for the B main feed pump recirculation line i isolation valve 2-FCV-3-84. Repair to this line is discussed in j paragraph 4.c. The unit reached full power on November 27, 1993. The !
unit operated at power until December 3, when the unit experienced a !
reactor trip due to a failure of the voltage regulator for the main 1 generator. At the end of the inspection period, the unit had been taken i to MODE 4, with post trip recovery activities in progres !
! Operational Safety Verification (71707) i
' Daily Inspections The inspectors conducted daily. inspections in the following areas:
control room staffing, access, and operator behavior; operator adherence to approved procedures, TS, and LCOs; examination of panels containing instrumentation and other reactor protection system elements to determine that required channels are operable; .
and review of control room operator logs, operating orders, plant deviation reports, tagout logs, temporary modification logs, and tags on components to verify compliance with approved procedure The inspectors also routinely accompanied plant management' on plant tours and ' observed the effectiveness of management's influence on activities being performed by. plant personne (1) The inspectors responded to the control room on November 17 to monitor operator actions regarding a' failure of a normal charging flow control valve on Unit 2. Earlier on Novembe , Unit 2 was shutdown from approximately 100% reactor power to allow for inspections to be performed on the CCS supply check valves to the thermal barrier heat exchangers (this problem is discussed in paragraph 4.a). Problems encountered during unit cooldown in MODE 3 and operators response to the-problems are described belo '
At 2:30 p.m. on November 17, with Unit 2-in MODE 3 at-approximately 377* F and 620 psig, operators had been-increasing pressurizer level per procedure to 55% during the unit cooldown. While attempting to secure the level increase, operators became aware that the common flow control valve for both CCPs, 2-FCV-62-93, had failed to
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adequately control pressurizer level (failed open). !
Pressurizer level began an increase at the rate of ,
approximhtely 1% per minute. RCS letdown was inservice at ;
the maximum rate and one CCP was running to provide normal chargin ,
Operators immediately took actions to manually control the output of 2-FCV-62-93 per 2-50-62-1, CHEMICAL AND VOLUME CONTROL SYSTEM, Revision 10. However, it appeared to :
operators that the air supply regulator for the valve was not providing the required amount of air pressure to operate the valve. Operators then took actions to control charging flow by manipulating an upstream manual isolation valve, 2-VLV-62-535, located locally in the CCP room. This action adequately stopped the pressurizer level increase at :
approximately 78%. With the unit in a stable condition, a WR was written to take actions to increase the output of the air regulator for 62-93. The as-found air pressure was approximately 28 psi and was adjusted to greater than 50 psi. The valve was later placed back in service and subsequent operation of the valve was acceptable. The licensee suspected that the air regulator setpoint may have been too low to operate the valve in the high differential pressure conditions present during the unit cooldown. The root cause determinations, short and long term' corrective actions, and extent of condition of the problem are further discussed in paragraph The licensee performed an incident investigation because of the even The inspectors concluded that operator response to the event was good. Operators utilized procedures, when applicable, to institute immediate corrective actions for the lack of charging control. In addition, the inspectors specifically noted the decision not to put excess letdown in service was appropriate due to the limited effect this action would have in placing the unit in a safer condition. This limited effect was due to the high differential pressure between charging pump output and RCS pressure and was recognized early in the event by operators. Communications between control room operators and operators performing local valve manipulations was also noted to be goo (2) On December 3, the inspectors responded to the control room to monitor recovery efforts for a Unit 2 reactor trip. The reactor tripped due to a failure of the main generator voltage regulator. The transient was first noticed when operators in the CR received an alarm for abnormal generator
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excitation. Operators noticed an abnormal excitation field and attempted to manually base adjust the regulator; however, coincident with these actions, high stator water temperature caused the turbine to trip, which in turn initiated a reactor trip. The unit response to the
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transient appears to have been normal. The unit was '
stabilized in MODE 3 at approximately NOT and NOP with the ;
SGs being supplied by auxiliary feedwater. Operator '
response to the reactor trip appeared to be good. Several secondary problems were noted which included a leak on a condensate booster pump bypass check valve bonnet and a small casing crack on the 2A condensate booster pum :
The licensee had previously experienced numerous problems ;
with the voltage regulator since a Unit 2 reactor trip which occurred on March 1, 1993, involving steam intrusion into the regulator cabinet. Evaluation of the licensee's post -
trip review for the current event and corrective actions taken will be addressed in IR 327, 328/93-5 t b. Weekly Inspections The inspectors conducted weekly inspections in the following areas: operability verification of selected ESF systems by valve alignment, breaker positions, condition of equipment or component, and operability of instrumentation and support items essential to system actuation or performance. Plant tours were conducted which included observation of general plant / equipment conditions, fire protection and preventative measures, control of activities in progress, radiation protection controls, missile hazards, and plant housekeeping conditions / cleanlines i On December 2, the inspectors toured Unit 1 lower contairaen Areas inspected included the raceway, fan rooms, and areas inside the polar crane wall. Housekeeping was noted to be average, considering the amount of work activities ongoing. Progress was noted on repairs to degraded coating located in the area of the containment sump and to repairs to liner degradation identified in the raceway. On going work activities associated with the repairs -
appeared to be in accordance with applicable work control procedures. The inspector questioned the licensee regarding the structural integrity of an 8 inch stainless . steel line which connects the PRT to the RCDT. The line had external damage from an unknown source. The damaged portion was located approximately 25 feet downstream of 1-FCV-68-310. The line is low pressure and with the unit in MODE 5, the inspectors did not consider it an immediate safety issue. At the end of the inspection period, the licensee was performing an engineering assessment of the damaged lin c. Biweekly Inspections The inspectors conducted biweekly inspections in the following areas: verification review and walkdown of safety-related tagouts in effect; review of the sampling progra'n (e.g., primary and secondary coolant samples, boric acid tr.nk samples, plant liquid and gaseous samples); observation of control room shift turnover;
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review of implementation and use of the plant corrective action program; verification of selected portions of containment isolation lineups; and verification that notices to workers are posted as required by 10 CFR 19.
d. Other Inspection Activities Inspection areas included the turbine building, diesel generator building, ERCW pumphouse, protected area yard, control room, Unit l' containment, vital 6.9 KV shutdown board rooms, 480 V breaker and battery rooms, and auxiliary building areas including all accessible safety-related pump and heat exchanger rooms. RCS leak rates were reviewed to ensure that detected or suspected leakage from the system was recorded, investigated, and evaluated; and that appropriate actions were taken, if required. RWPs were reviewed, and specific work activities were monitored to assure they were being accomplished per the RWPs. Selected radiation protection instruments were periodically checked, and equipment i operability and calibration frequencies were verifie ,
e. Physical Security Program Inspections in the course of the monthly activities, the inspectors included a review of the licensee's physical security program. The performance of various shifts of the security force was observed in the conduct of daily activities to include: protected and vital area access controls; searching of personnel and packages; escorting of visitors; badge issuance and retrieval; and patrols and compensatory posts. In addition, the inspectors observed protected area lighting, and protected and vital areas barrier integrity.
f. Licensee NRC Notifications (1) On November 10, 1993, the licensee made a four hour notification to the NRC as required by 10 CFR 50.72 regarding the entry into a Notification of Unusual Event (NOVE). At 5:55 p.m. on November 10 the NOUE was declared due the transportation of an injured, contaminated individual to an offsite medical facility. The individual sustained an internal injury to his back during work in the Unit 1 ice condenser. The individual was transported wearing anti-contamination clothing which had a beta-gamma reading of less than 100 counts per minute. At 6:20 p.m.,
the NOUE was terminate (2) On November 16, 1993, the licensee made a one hour notification to the NRC as required by 10 CFR 50.72 regarding the identification that Unit 2 may be operating outside of its design basis. Similarly, a four hour -
notification as required by 10 CFR 50.72 was made for Unit I regarding the identification of a degraded condition while .
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shutdown. Both notifications were made based on radiograph- :
inspections performed on Unit I which revealed that 7 of 8 :
check valves in the supply lines to the RCP thermal barrier j heat exchangers were stuck in the open position.- The eighth- ;
valve's piston was identified as being installed in the i incorrect orientation. At the time of discovery, Unit I was j in MODE 5 and Unit 2 was operating in MODE I at j approximately 100 % power. The check valves are designed to i close on reverse flow in the event of a rupture of a tnermal- a barrier heat exchanger to protect CCS piping from over i pressurization. This event is further discussed in !
paragraph l (3) On November 18, 1993, the licensee made a four. hour <
notification to the NRC as required by 10 CFR 50.72 !
regarding an earlier notification to the National Response !
Center. The notification to the response center was.due to :
a hypochlorite spill of approximately 150 gallons from an j ERCW feed skid. None of the solution reached the Tennessee 1 Rive .l
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(4) On December 2, 1993, the licensee made a one hour -j notification to the NRC as required by 10 CFR 50.72 -l regarding the identification that Unit 2_being in an unanalyzed condition. Similarly. . a' four hour notification !
as required by-10 CFR 50.72 was made for Unit I regarding i the identification of a degraded condition while shutdow a Both notifications were made based on the identification i that two penetrations'from each unit's containment, were not l properly tested for containment integrity. For each unit, a 'j valve on the penetration piping was determined to be'a vent -
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valve while it was previously assumed to be an angle _j isolation valve. This event is further discussed in -
inspection report 327,328/93-5 j
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(5) On December 3, 1993, the licensee made a four hour 1 notification to the NRC as required by 10 CFR 50.72- 1 regarding an automatic reactor trip which occurred or Unit ,
2. At 10:56 a.m.', the reactor tripped from full power as 1'
result of an automatic turbine trip initiated by a ' problem with the main ~ generator excitation system. _All systems ,
functioned as required after the trip. This. event is !
further discussed in paragraph 3.a.(2). j
.i Within the areas inspected, no violations were identifie . Maintenance Inspections (62703 & 42700) .
During the reporting period, the inspectors reviewed maintenance !
activities to assure compliance with the appropriate procedures and ;
requirements. Inspection areas included the following:
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l a. During the inspection period, the inspectors monitored licensee I troubleshooting and corrective maintenance activities regarding :
CCS check valves. On November 14, the licensee determined through i radiograph inspection that 7 of 8 Unit 1 CCS check valves for the :
RCP thermal barrier heat exchangers were stuck in the open position. The eighth valve's internals were determined to have been installed upside down. The licensee determined from t maintenance records that no work had been performed on the ,
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incorrectly assembled valve and concluded that it had been received in that condition from the vendor. Unit I was in MODE 5 at the time of the inspectio Based on the results of the Unit 1 inspections, the licensee determined that inspections of the Unit 2 CCS check valves should be performed immediately. Unit 2 was operating at 100% power at the time of the decision. On November 16, Unit 2 began a power decrease from approximately 100% reactor power in preparation to enter Mode 4 to conduct an inspection of CCS check valves in the CCS supply lines to the RCP thermal barrier heat exchangers. On November 18, the licensee completed the inspection of the Unit 2 ,
valves and found that seven of the eight valves on Unit 2 were
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also stuck ope ,
The valves of concern are piston type, gravity operated check valves. There are two valves in series on each CCS supply line to each RCP thermal barrier heat exchanger. The valves are designed
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for RCS pressure. The safety function of the valves is to prevent over pressurization of the low pressure portions of the CCS in the event of failure of a RCP thermal barrier heat exchanger. The licensee had not included these check valves in their IST program .
since Sequoyah was not a code plant (ANSI B31.1 for design and ANSI B31.7 for testing and inspection). However, the licensee was planning to add the valves to either their ASME Section XI testing program or an augmented inspection / testing program in the futur An NRC inspection in October 1993 resulted in the licensee agreeing to test the subject valves in each Unit's respective cycle 6 refueling outage. The Unit 1 inspections were being conducted based on this agreemen The licensee determined that the most probable root cause of_ the sticking of the check valves was oxide wedging in the crevice ',
between the stainless steel valve stem and the carbon steel body of the valve. Contributing causes were dissimilar metal corrosion, previous poor water chemistry due to past history of ,
river cooling water intrusion into the CCS through CCS heat exchanger tube leaks, and faihre to periodically cycle the valves. The short term corrective action for the Unit 2 valves was to refurbish all eight valves and return them to service until the next refueling outage in April 1994. Long term corrective actions for both units have not been finalize .
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While performing this inspection, the inspectors were informed that in early 1993 the license had identified other check valve sticking problems in the CCS. The licensee was performing maintenance on the Unit 2 CCS thermal barrier booster pump "B" discharge check valve, (a spool type, gravity operated valve) when it was determined that the valve was stuck partially open due to the buildup of an oxide substance. The valve was refurbished and returned to service; however, the licensee did not expand the scope of the inspection to determine if other check valves within the CCS were similarly affected by an oxide buildu The inspectors review of the above problem in conjunction with past problems involving check valve operation in the CCS resulted in a conclusion that the licensee's program for review of potential generic issues continues to be weak. Although immediate management focus on Unit 2 safety was appropriate after identification of the Unit 1 problem, and Unit 2 was shut down for corrective actions, more aggressive technical review of past problems could have resulted in inspections prior to Unit 2 restart. The inspectors concluded that this area needs continuing management attention, b. During the inspection period, the inspectors reviewed licensee corrective actions for a Unit 2 event which occurred on November 17 involving the failure of the common discharge flow control valve for both CCPs, 2-FCV-62-93. Operational aspects of the event were previously discussed in paragraph 3.a. The subject valve was manufactured by Masonelian; however, modifications were incorporated in 1974 to install a Copes-Vulcan actuator and other components. The valve is air operated and fails open via a
spring. The valve apparently failed to operate during the event
, due to an inadequate air supply from its air regulato Subsequent investigation revealed that the installed air regulator was not properly set due in part to errors made during a conversion process in .991 from the use of calibration cards to the Instrument Data Package (IDP) process. The conversion process was performed per SSP-6.53, PREPARATION, CONTROL AND REVISION OF INSTRUMENT MAINTENANCE DATA PACKAGES. The regulator for 2-FCV-62-93 was also identified as being underranged. Based on the information available to the inspectors by the end of the inspection, relevant licensee actions leading up to the event were as follows:
Date Event pre-1974 Components for the original design flow control valve for both units were all manufactured from Masonelian components. Required air pressure for valve was approximately 30 ps Copes-Vulcan actuator and other components were added as design improvement. A drawing change
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indicated that required air pressure for valve was greater than 50 psi and less than 100 ps The increased supply air pressure requirement was also incorporated in the valve's calibration ;
car Licensee incorporated the calibration card to IDP changeover per SSP-6.53. During this process, only the Masonelian vendor manual was referenced without considering the additional Copes-Vulcan components which increased the air pressure requirements. The incorrect value of 30 psi was incorporated into the ID Information on calibration card was not transferred to IDP because process did not require it due to the calibration card not being considered as a controlled document. Both Unit I and 2 air regulators for the subject valves remained set at above 50 psi until the next usage of the incorrect ID /92 The incorrect IDP was used to set air regulator for Unit 2 flow control valve 2-FCV-62-9 /18/93 The incorrect IDP was used to set air regulator for Unit I flow control valve 1-FCV-62-93
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10/04/93 WR # 213895 was initiated on Unit I flow control valve 1-FCV-62-93 due to operators observation of erratic contro /17/93 WR # 213895 was worked for Unit 1. Instrument Maintenance (IM) personnel noted that valve worked better when the air supply pressure was increased above 50 psi. IMs also ncted that the old calibration card indicated valve should be set at greater than 50 psi. The incorrect IDP was not placed on administrative hold at this tim /18/93 The IMs inspected the Unit 2 valve for similar problems. The air regulator was found set at !
greater than 50 psi (actually found at 95 psi '
which indicates that the regulator may have been degraded). The IMs concluded the Unit 2 valve '
was not an immediate proble ;
10/24/93 The air regulator for the Unit 2 flow control i valve 2-FCV-62-93 was replaced. This was due to 1 it meeting the air regulator replacement l criteria which were part of corrective actions l for recent air regulator failure event (see IR j i
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327,328/93-50). The incorrect IDP value was again utilized to set air regulator at 30 ps The post maintenance test for valve was performed satisfactorily due to test not being conducted at the most severe differential pressure conditions.
10/28/93 New, correct IDP issued for Unit I valve.
10/29/93 New, correct IDP issued for Unit 2 valve.
11/17/93 Unit 2 experienced failure of 2-FCV-62-93 due to incorrect air regulator setting. The valve failed to operate under high differential pressure conditions.
The inspectors reviewed the event for root cause determinations.
It was concluded that an initial error was made in 1974 in that modifications made to the valve were not adequately annotated in the vendor manual package for the valve. This problem was not identified during the calibration card to IDP changeover in 1991 due to the vendor source documentation being incorrect. The inspectors also considered that a review of the old calibration card data during the 1991 IDP changeover could have identified a discrepancy in the air regulator setpoints. An additional error, was that the incorrect data package, as identified by IMs on October 17, 1993, was not placed on administrative hold. This allowed the incorrect value to again be installed on the Unit 2 valve on October 24, 199 i The inspectors concluded that the IDP, used to adjust the air regulators for both 1-FCV-62-93 and 2-FCV-62-93, was inadequate, in that, it did not contain the correct regulator setpoint information. The failure to adequately maintain the required setpoint data in the IDP, as controlled under SSP-6.53, is identified as a violation (NCV 327,328/93-52-01). This violation will not be subject to enforcement action because the licensee's effort in identifying and correcting the violation meet the criteria specified in Section VII.B of the Enforcement Policy.
During the event investigation, the licensee also determined that ,
the air regulator installed on 2-FCV-62-93 was rated for 3 to 35 psi working pressure, whereas, the required pressure was greater than 50 psi. The inspectors recalled that during' the event recovery, the air regulator for 2-FCV-62-93 had been adjusted to approximately 52 psi. The inspector questioned whether it was common practice to adjust air regulators beyond their design pressure and whether a justification for the 2-FCV-62-93 was j required. The licensee performed a justification for the 1 adjustment made to the regulator. Continued operation was based !
on the regulator body being the same as a 100 psi re plator and j the only difference being the size of an internal s 9 The ;
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licensee reviewed the use of lower pressure regulators on components requiring higher pressures and concluded this practice had occurred frequently in the past. Although the inspectors concluded that the justification for overranging the 2-FCV-62-93 was acceptable on a temporary basis, the inspectors also concluded that the previous acceptability of this practice was a weakness in l the area of engineerin In addition to the above, the inspector also reviewed the post maintenance testing which was performed after.the Unit 2 air regulator replacement on October 24, 1993. The testing, which included valve stroking, was performed with a low differential pressure when compared to the differential pressure for the valve failure that occurred on November 17. During the failure, the differential pressure was approximately 1800 psi. The post maintenance test did not challenge the component at the highest differential pressure anticipated during expected plant evolutions and did not identify the problem. However, had the correct design information been available to properly set the air regulator, the ,
event would not have occurre Corrective actions for the event included replacement of the underranged regulator for 2-FCV-62-93 and correction of the 1DP for the subject valves. The licensee also performed an extent of condition inspection which included a system engineer review of 74 operationally significant air operated valves to determine if the valves had previously operated at their respective worst case ,
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conditions. Eighteen valves were identified which had not met the criteria since previous maintenance activities were performed on :
the valves. Engineering data reviews and valve walkdowns were performed to ensure correct regulator settings for these valve Na other major discrepancies were identifie ;
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the performance of a cross reference check comparing previous calibration card data, existing IDPs, valve contract information, and walkdown data for all of the operationally significant and other air operated valves. The inspectors will continue to monitor the licensee's corrective actions regarding air regul ator The inspectors concluded that, although '1e root cause of this l event was different from other recent air regulator failures, the '
material condition, maintenance, and design requirements of air regulators is in need of additional management attentio On November 24, 1993 a leak was observed on the spoolpiece for the
' B main feedwater pump recirculation line below the weld between ,
l the automatic isolation valve (2-FCV-3-84) and the manual isolation valve to the main condenser. Initial evaluation of the '
leak concluded that the spool piece may have a defect. During the next few hours, the flowpath was isolated by shutting the manual
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isolation valves (B main feed pump was not in service).
Subsequently, the defect area was radiographed to determine the extent of the defect. X-ray evaluation co icluded that the area of concern had experienced significant erosion on the inside circumference of the piping spoolpiece at the defect locatio ,
Plant management directed that immediate actions be taken to '
manually isolate the same flowpath for.the A MFP recirculation line and to radiograph the same location for this line. X-ray evaluation of the A pump recirculation line did not identify any degradation in the area.
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Over the next 2 days, the licensee replaced the defective line including valve 2-FCV-3-84 with a like valve from Unit 1. The -
licensee had experi m aJ erosion in the past in this area for these valves. They had installed new stainless steel, schedule 80 transition / spool pieces during the Unit 2 forced outage. Maximum total operational time for this flowpath since replacement was .
estimated to have been approximately 10 days. This time incisdes the period when suspected leakage past the valve had occurre Examination of the suspect area after removal showed extensive wear of the spoolpiece below the weld attaching the spoolpiece to 2-FCV-3-84. The erosion wear was 360* around the inside circumference of the transition piece appr-oximately 1/2 to 3/4 inch in length. The wear depth approached through wall over the entire circumferenc ,
The licensee implemented augmented inspections to monitor for the erosion in the near term. These inspections included temperature monitoring of the piping downstream of the valves to monitor for leakage. Also, a weekly ultrasonic examination of the suspect piping areas was being accomplished. The inspectors concluded the licensee's augmented inspections should provide early warning of -
piping wear in the area of this proble .
2-FCV-3-84 is an air operated, four inch angle valve manufactured by the Yarway Corporation. The licensee was continuing with the root cause investigation when the inspection period ended. This investigation will propose longer term corrective actions for the -
proble Within the areas inspected, one non-cited violation was identifie !
I 5. Surveillance Inspections (61726 & 42700) l
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During the reporting period, the inspectors reviewed various .
surveillance activities to assure compliance with the appropriate procedures and requirements. The inspection included a review of the .
following procedures and observation of surveillance:
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a. 2-SI-0PS-0680137.0,. REACTOR COOLANT SYSTEM WATER INVENTORY, t Revision 3. The inspectors reviewed the subject surveillance '
which had been accomplished on November 29, 1993. The test involved determination of Unit 2 total, identified, and i unidentified leakage from the RCS as required by TS surveillance requirement 4.4.6.2.1.d. Based on the test results, the licensee determined that all leakage parameters were within the TS :
allowable. The inspectors review of the completed SI supported (
the licensee's conclusion. However, several items recorded 'in the - :
SI package indicated that attention to detail was lacking during i SI performanc For example, in APPENDIX C, Step 2.0; the .
operator indicated that instrument LO480A was used to record pressurizer level data. During review of the data provided,.the-inspector determined that SI data was recorded-from instrument ;
LO481A. Also, data recorded was not always from the same line of data printed for the specific time interval from.the computer' ;
printou The inspectors independently calculated the leakrates using data :
from the same computer printout and the NRC independent leakage i measurement program. The results of the leakage compared'with the _l licensee's data in a satisfactory manner. On December 11, 1993 -!
the inspectors discussed the results of this inspection activity .i with operations management. They agreed with the inspector's :
attention to detail comments.- i b. 2-SI-IFT-003-518.3, FUNCTIONAL TEST OF ENVIRONMENTAL ALLOWANCE !
MODIFIER (EAM)/ TRIP TIME DELAY (TTD) PROTECTION SET III, Revision j 6. The inspectors monitored activities associated with the ,
subject surveillance on November 28, and reviewed a copy of the- !
completed SI on November 29, 1993. No procedural discrepancies :
were identified during the revie '
However, during a field walkdown of auxiliary instrument room 2 at-approximately 3:00 p.m. on November 28, the_ inspectors noticed ,
that no instrument technicians were in the vicinity of the- l protection rack II. test area. The inspector. observed that test
equipment was connected in the rack. The procedure review l identified that the SI was started approximately 9:23 a.m.'and ;
completed approximately 6:34 p.m. on November 28, 1993. The I ir.spectors discussed the normal duration that this test should take with I & C management. Management agreed to review this test with their personne On December 2, 1993, the. inspectors met.with I & C management to discuss the surveillance time interval. The inspectors were informed that two surveillances had been performed in series during the period of time in question. The I & C technicians had performed 2-SI-IFT-068-044.3, FUNCTIONAL TEST OF AT/TAVE CHANNEL'
III, RACK 10 LOOP T-68-44 (T-431/432), Revision 6 between 9:17 a.m. and approximately 1:30 p.m. 2-SI-IFT-003-518.3 was performed between approximately 1:30 p.m. and 6:34 p.m. The inspectors
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considered that reasonable time was expended on each surveillance -
and performance of the surveillances in series minimized TS LC0 tim Within the areas inspected, no violations were identifie ,
6. Evaluation of Licensee Self-Assessment Capability (40500)
During this inspection period, selected reviews were conducted of the licensee's ongoing self-assessment programs in order to evaluate the effectiveness of these program On November 20, 1993, the inspectors attended a special PORC meeting to review key component / personnel performance issues which ,
where addressed during the Unit 2 forced outage shutdown beginning November 16, 1993. The issues discussed included the following:
containment liner inspections; voltage regulator repairs; CCS check valve corrective actions; RCS leakage; boric acid integrator problems; reactor head vent valves; RCP standpipe alarms; 4 secondary plant erosion inspections, and secondary leak repair activitie The inspectors concluded that most of the presentations made to the PORC committee were well prepared and in a format that adequately described the problem, root cause, and proposed / completed corrective actions. Several of the presentations; however, were not as detailed, and required the PORC and other personnel present to further question the presenters to fully evaluate the issu . On November 23, 1993, the inspectors monitored activities in a MRRC meeting. The purpose of the meeting was to review several items for deferral from the Unit 1 Cycle 6 outage. The review process was accomplished as described'in the restart plan. System ,
engineers presented the issues along with justifications for deferral. The inspectors concluded that this process was being ,
implemented as described in the restart plan. However, the inspectors noted that outage management deleted approximately 28 ;
work request items from the Unit 1 outage at this meeting. The inspectors requested and were provided a copy of each deletion -
package for review. The inspectors reviewed each item and concluded that some of the work request deletions lacked an adequate description by system engineers as to why they could be ,
delete j On November 30, 1993, the inspectors met with' technical support management to discuss the items deleted with questionable justifications. Licensee management was able to demonstrate that ,
adequate justifications existed to delete questioned items from the Unit 1 Cycle 6 outage. However, they also agreed that written documentation for deletion was not clear and required additional wor i
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Within the areas inspected, no violations were identifie . Licensee Event Report Review (LER) (92700)
The inspectors reviewed the LERs listed below to ascertain whether NRC reporting requirements were being met and to evaluate initial adequacy of the corrective actions. The inspector's review also included followup on implementation of corrective action and/or review of t licensee documentation that all required corrective action (s) were either complete or identified in the licensee's program for tracking of outstanding action (Closed) LER 328/93-05, Manual Actuations of the Reactor Trip Breakers as a Result of Malfunctioning Demand Step Counters. The issue involved operators manually tripping open the Unit 2 reactor trip breakers on-three separate occasions due to demand step counter malfunctions for counters installed in the Shutdown Bank "D" position. Unit 2 was in
MODE 3 each time the breakers were opened. The actions were in accordance with TS LC0 3.1.3.3. The licensee reviewed each event and all of the events as a whole and concluded that the three counters display tumblers had excessive play and had been procured from one ,
supplier. A counter from a different supplier was tested and placed in service. Long term corrective actions include proposed replacement of the electro-mechanical demand step counters with electronic counter '
The new counters are scheduled for replacement on Unit I during the current refueling outag Within the areas inspected, no violations were identifie . Action on Previous Inspection Findings (92701,92702)
(Closed) IFI 327, 328/93-33-06, NRC Identification of Unevaluated Boric Acid Conditions on the Inside of the Unit 1 Containment Vessel Steel Liner and the Design of the Liner Flashing. This issue was previously >
discussed in NRC Inspection Report 50-327, 328/93-42. The IFI involved NRC questions relative to possible containment liner damage due to corrosion caused by leakage from components above the raceway (lowest *
accessible point on the inside of the containment liner). The identified leakage ranged from boric acid leakage running down the liner from system components to flooding of the containment raceway due to previous containment cooler leakage. The main area of concern was the containment liner behind a stainless steel flashing which enclosed insulating material at the interface between the concrete raceway floor 1 and the containment liner wall. Due to deterioration of the sealing compound between the flashing and the containment liner, the suspect leakage had previously migrated behind the flashin During the current inspection period, the inspectors and the licensee continued to investigate this problem. The licensee removed ;
approximately six small areas of the flashing for inspection. During a containment entry early in the inspection period, the inspectors noted that a substantial amount of standing water existed in the cavity ,
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between the raceway concrete floor and the containment line Numerous locations on the liner also exhibited surface corrosion. The following l summarizes licensee actions and followup inspection activitie !
Unit 1 Essentially 100% of the flashing and enclosed insulation was remove This allowed access for inspection of the area in question (concrete floor to steel liner wall joint) to evaluate any corrosicn damage to the steel liner. The adhesive between the containment liner and the ,
"Foamglas" insulation was found to be intact which assisted in precluding water entry between the insulation and the containment line '
However, the seal (Carbolene 225 per drawing) between the concrete floor slab and the steel liner leaked allowing water to enter the cavity between the concrete and steel liner. The licensee removed the sealing 4 material and on November 18, 1993, approximately one third of a 55 gallon drum of water had been removed from the cavity. The water was analyzed and found to have a PH of 8.7 with a tetra borate concentration of approximately 600 ppm. There was some indication of corrosion (rust)
on the steel liner at the joint between the floor slab and the steel >
liner. Although the licensee considered the corrosion to be minimal, I approximately 15 locations were selected for removal of the rust and i determination of liner thickness. Locations were selected based on worst observed conditions and areas where water had been observed leaking from above. By the end of the inspection period, the licensee concluded that the degradatien identified would not affect the design function of the liner; however, three locations were identified as being slightly below the nominal allowable thickness of 1.375 inches less the 10 mil material tolerance. The three identified areas were 8, 5, and 2 mils below the nominal valu .
The inspectors reviewed the design and "as-built" drawings and discussed the design and "as-built" condition of liner and floor slab area with .
licensee engineering personnel. In addition, the field condition of the liner and floor slab area was observed with the following results:
The liner did have areas of rust at the liner to floor join However, based on visual observation of the 15 areas after cleaning, and preliminary ultrasonic (UT) thickness inspection of some of the areas, ,
degradation to the liner appeared minimal. Based on questions by the inspectors, the licensee selected two additional areas for inspection, .
which appeared to have a heavy buildup of rust. After preliminary preparation for inspection, the depth of corrosion at these areas also appeared to be minimal. The inspectors also pointed out to licensee :
personnel that without cleaning at least some of the inspection areas to bright metal, the exact depth of corrosion could not be accurately judged. The licensee agreed that the preparation technique could be improved to allow for better evaluation of corrosion. The licensee utilized this guidance for some of the worst case inspection point The liner to floor slab joint cavity was visible only about 6" deep, or to the first horizontal weld " leak chase" channel. All standing water
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had been removed; however, the top surface of the channel was still we This fact, plus review of the design drawing, indicates that water in i the cavity has probably migrated down between the floor slab and the 1/4" bottom liner. By the end of the inspection period, the licensee had not determined the exact corrective actions to be taken for this Unit I concern. The inspectors will continue to monitor the licensee's actions in this are During the inspection, the licensee removed 7 of the 8 floor plates ;
covering the bottom liner plate weld " leak chase" test connection boxe ~
These boxes are approximately l' X l' square and 4" deep embedded in the raceway floor. Six of the 7 boxes did not have cover gaskets installed, as shown on the drawing, and were full of wate The seventh box had a '
cover gasket installed and was dry.. The water in these boxes did not appear to have any connection to water at the liner wall to floor cavity joint since the " leak chase" pipes between the boxes and the " leak
! chase" channels are enclosed in sleeves that are seal welded to the bottom of the boxes and the " leak chase" channels. It appears the water entered the boxes at the cover plates since gaskets were not installe The source of the water was presumed to be the same as the water identified in the cavity between the liner and raceway floo Unit 2 The licensee selected 8 locations and removed the flashing and insulation at the floor to liner joint for inspection of the joint are The locations were selected based on the Unit I findings and Unit 2 areas with evidence of water leaks. On November 18, 1993, the flashing and insulation had been removed on 7 of the 8 areas. For 1 of the 7 areas, the sealing material was removed from the cavity. The licensee's inspection revealed a much better seal than Unit I and no water was foun ,
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The inspectors observed the other 7 areas and no moisture was note The eighth area could not be initially inspected due to standing water on the raceway floor from an ongoing cooler leak. After the water was removed, the area was inspected and found to be dry. Although some rust ;
was observed on the liner, it appeared not to be significant. The inspectors also noted that the seal between the floor and the steel !
liner appeared to be in good condition. Based on discussions'with licensee engineering personnel, the seal appeared to be a much better !
seal than that found on Unit 1. The seal appeared to be some type of formed material with caulking underneath and on both sides. Based on review of the drawings, it was not clear why the two units had different sealing material The licensee also removed the " leak chase" test connection box cover ]
The inspectors observed removal of the covers for 2 of the boxes and both were full of water. Neither had cover plate gaskets installe !
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Status of issue By the end of the inspection period, the licensee was still evaluating the extent of corrosion damage to the containment liner and other necessary inspections and repairs for Unit 1. On Unit 1, there exists a ,
strong probability that water may have migrated between concrete and containment liner interfaces. This condition does not appear to exist on Unit 2. The " leak chase" test connection boxes on both units which were identified containing standing water were left as found. The -
licensee considered that this condition would maintain the lowest oxygen atmosphere until a permanent resolution could be evaluated. Future NRC review of corrective actions regarding both Unit I and Unit 2 will be performed during review of the licensee's violation respons Conclusions t
The inspectors reviewed this issue with regard to regulatory significance. This issue was identified by the NRC during a routine containment tour during the Unit 1 Cycle 6 refueling outage. Once further licensee inspections were performed, the existence of unknown water accumulation, some containment liner degradation, and design inconsistencies were identified. The inspectors considered that this was a significant example of a lack of questioning attitud The inspectors reviewed the licensee's surveillance procedures used for inspecting the containment liner. The procedures for Units 1 and 2 respectively, SI-254 and SI-254.2, CONTAINMENT VESSEL AND SHIELD BUILDING INTEGRITY VERIFICATIO The inspectors concluded that these procedures were inadequate, in that, they did not contain provisions to periodically inspect the area of the containment liner which was covered by stainless steel flashing. This area of the liner is one of the most susceptible areas for corrosion to occur due to it being a containment lowpoint and in an area frequently exposed to component leakage and localized flooding. In addition, previous maintenance on the RTV seal between the flashing and the containment liner was poor. This issue will be identified as a violation of Technical Specification 6.8.1 due to SI-254 and SI-254.2 being inadequate (VIO 327,328/93-52-02).
Within the areas inspected, one violation was identifie . Cold Weather Preparations (71714)
During the inspection period the inspectors reviewed the licensee's freeze protection program, and its implementation, to protect safety-related systems against extreme cold weather. There are several procedures used to implement the progra Each procedure is performed at specified frequencies (once per cold weather season, monthly, or weekly) between October 1 and March 31. The inspectors also verified that the licensee has implemented a program for testing heat trace and cabinet heaters for critical components associated with feed water flow transmitters and RWST and CST level transmitters. The freeze protection ;
procedure with the largest scope is 0-PI-0PS-000-006.0, Freeze l l
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Protection, Revision 1. This PI identifies equipment and/or areas needing freeze protection, identifies means of protection, and provides requirements to ensure operability during the months needed. Other procedures are specifically related to heat trace functional testing, insulation inspection, and modifications to protect instrumentation in the main steam valve vaults. The inspectors reviewed the most recently performed of each of the following procedures. Each procedure had been performed at its required frequency and documentation was adequat PI-0PS-000-006.0, FREEZE PROTECTION, Revision ,
1(2)-PI-EFT-234-706.0, FREEZE PROTECTION HEAT TRACE FUNCTIONAL TEST, Revision PI-MIN-000-706.0, VITAL INSTRUMENTATION SENSE LINE INSULATION INSPECTION, Revision The licensee documents freeze protection deficiencies by the use of a DN, which becomes a part of the procedure package, for each component which does not meet the acceptance criteria of a freeze protection procedure. WRs and W0s are initiated when necessary and are also documented on the DN. The inspectors noted that each of the reviewed procedures had one or more DNs attached and the DN adequately described the deficiency and the corrective action which was initiated. The inspectors also reviewed the followup of corrective actions with personnel in the work planning group. Work Planning maintains a " Freeze Protection Report" which lists all open WRs and W0s related to freeze protection and the date when the items are scheduled to be worke Additionally, this report is used to identify where compensatory actions may be necessary if freezing conditions are anticipated and corrective maintenance has not been completed on a freeze protection componen ,
The inspectors concluded from procedure reviews, review of outstanding items on the " Freeze Protection Report," and walkdowns of selected freeze protection equipment, that the licensee is implementing an '
adequate program for the protection of' critical components during ,
extreme cold weather condition i
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Within the areas inspected, no violations were identifie . Exit Interview
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The inspection scope and results were summarized on December 6, 1993 with those individuals identified by an asterisk in paragraph I abov The inspectors described the areas inspected and discussed in detail the ,
inspection findings listed below. Proprietary information is not contained in this report. Dissenting comments were not received from the license ,
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Item Number Description and Reference NCV 327, 328/93-52-01 Failure to adequately maintain the required setpoint data in the IDP, as controlled under SSP-6.53 (paragraph 4b). *
VIO 327, 328/93-52-02 Violation of Technical Specification I 6.8.1 due to SI-254 and SI-25 being inadequate (paragraph 8).
Strengths and weaknesses summarized in the results paragraph were i discussed in detai ,
Licensee management was informed of the items closed in paragraphs 7 i and ;
11. List of Acronyms and Initialisms ASME - American Society of Mechanical Engineers i CCP -
Centrifugal Charging Pump CCS -
Component Cooling Water System CFR -
Code of Federal Regulations CR -
Control. Room CR0 -
Control Room Operator DN -
Deficiency Notice '
DRP -
Division of Reactor Projects ERCW - Essential Raw Cooling Water ESF -
Engineered Safety Feature FCV -
Flow Control Valve GPM -
Gallons Per Minute IDP -
Instrument Data Package IFI -
Inspector Followup Item ;
IM -
Instrument Maintenance i IR -
Inspection Report
IST -
Inservice Testing KV -
Kilovolt LC0 -
Limiting Condition for Operation 1 LCV -
Level Control Valve LER -
Licensee Event Report l
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MFP -
Main Feedwater Pump i MRRC -
Management Restart Review Committee !
NCV -
Non-cited Violation N0P -
Normal Operating Pressure l NOT -
Normal Operating Temperature ;
NRC -
Nuclear Regulatory Commission .
PORC - Plant Operations Review Committee PPM -
Parts per Million PRT -
Pressurizer Relief Tank PSIG -
Pounds Per Square Inch Gage QA -
Quality Assurance !
RCDT - Reactor Coolant Drain Tank
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RCS -
Reactor Coolant System RII -
NRC Region II RM -
Radiation Monitor RPM -
Revolutions Per Minute RWP -
Radiaticn Work Permit ~
RWST - Refueling Water Storage Tank SG -
Surveillance Instruction S0 -
System Operations SOS -
Shift Operating Supervisor SSP -
Site Standard Practice TAVE - Average Temperature of the Reactor Coolant System TS -
Technical Specifications URI -
Unresolved Item VIO -
Violation WO -
Work Order WR -
Work Request
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