ML20011E237

LER 89-012-01:on 890626,RCS Backleakage Through Safety Injection Sys Check Valve Occurred Three Times.Caused by Missing Rollpins Which Connect Valve Disc to Valve Disc Shaft.Rollpins Replaced & Valves reassembled.W/900131 Ltr

ML20011E237
Person / Time
Site:	Arkansas Nuclear
Issue date:	01/31/1990
From:	Ewing E, Millar D ARKANSAS POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
2CAN019012, 2CAN19012, LER-89-012, LER-89-12, NUDOCS 9002120252
Download: ML20011E237 (9)

Text

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['. 3 Arkanm Power & Ught Company 4?b West Cutrtat

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Latie Amk AR 7P203 Tel 501377 4333 i

[ January 31, 1990 I 2CANB19812 U. S. Nuclear Regulatory Commission Document Control Desk Mail Station P1-137 Washington, D. C. 20555

SUBJECT:

Arkansas Nuclear One - Unit 2 Docket No. 50-368 License No. NPF-6 Licensee Event Report No. 50-368/89-012-01 Gentlemen:

Attached is a supplemental report concerning a safety injection check valve malfunction due to missing internal parts resulting in reactor coolant system backleakage. This report is being supplemented to provide additional information received as a result of a metallurgical analysis and from inspections performed on the internals of other similar check valves.

~Very truly yours, E. C. Ewing General Manager, Technical Support and Assessment i e

ECE:0M:abw Attachment cc w/att: _ Regional Administrator Region IV U. S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 1000 Arlington, TX 76011 INPO Records Center 1500 Circle 75 Parkway Atlanta, GA 30339-3064

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i l Form 1062.01 A NRC Fo-e 166 U.S. Nuclear Regulatory Commission (9-83) Approved OMB Wo. 3150 0104 Expires: 8/31/05 LICENS[E CVENT REPORT (L E R)

FACILITY NAML (1) Arkansas Nuclear One, Unit Two IDOCs.ET NUMBER (2) IPAGE ())

10151010101 31 61 Bf110F10tB

_T11LL (4) $afety injection $ystem Check valve Malfunction Due to Missing Internal Parts Results in Reactor Coolant Systee Backleakage Evf 47 DATi (6) LfR NLe@[R (6) l REPORT Daff (?) OTHER FaCILITlf$ INVOLVt0 ($)

l I I l$equentiell IRevisioni i I ,

1 Month! Day l Year lYear I l Number I i Numt.er IMonth! Day lYear i Facility Names IDocket Number (s1 i l 1 i i I I I i i i 1016I0I0101 1

.01 61 21 61 81 91 81 91--I 01 11 21--I 01 11 Of Il 31 11 91 01 10161010101 i OPERATING 1 ITHl$ REPORT 1$ $UBMITTED PUR5UANT TO THE REQu!REMENi$ CF 10 CIR 5 MODE (9) l 41 (Check one or more of the followino) (11)

POWERl l_ t 20.402(b) l _ 1 20.40b(c) 1 2 1 50.73(a)(2)(iv) l_l 73.71(b)

LEVELI l _I 20.405(a)(1)(1) l_l 60.36(c)(1) l_ I 60,73(a)(2)(v) l_t 73.71(c)

(10) 1010101 1 20.40b(a)(1)(11) 1.,,,1 60.36(c)(2) l _ I 60.73(a)(2)(v11) l_l Other ($pecify in I.,,,1 20.4Db(a)(1)(111) lJ i 60.73(a)(2)(1) l _ l 60,73(a)(2)(v111)(A)I Abstract below and l_l 20.40$(a)(1)(iv) lJ 1 60.73(a)(2)(11) l _ l 50.73(a)(2)(v111)(B)l in Text NRC Form 1 I 20.405(e)(1)(v) l l 60,73(e)(2)(iii) l t 50.73(a)(2)(x) l 366A)

L1CIN$(( CONTACT FOR THl$ L(R (L2)

Name l_ Telephone Number (Area i Dana Miller, Nuclear $4fety and Licensing $pecialist l Code l 15t0111916141-13111010 COMPLETI ONE LINE FOR (ACH COMPONINT FAllukt DE$CRIBED IN THIS REPORT (13) l l 1 lReportablel i i i l IReportablel Causel$ysteel Component IManufacturert to NPRD$ 1 lCausel$ysteel Conoonent [Manufacturerl to NPRO$ I 1 1 i i 1 1 i l i I i x I Al BI I I I VI Al $1 81 61 Y I i 1 1 I I I 1 1 I i 1 1 1 I I I i i l i i I i i I i 1 1 I I I I I I I I I I I I I l 1 1 I i 1

$UPP L EME N" RfPORT (WPECTLD (14) i LAPECTLD 1 Month Day lYear

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_l l Yes (If ves, conolete Expected $uboission Date) IKl No l DATE (15) l I I 1 l 1 ABSTRACT (Limit to 1400 spaces, i.e., approximately fif teen single space typewritten lines) (16)

On June 26, 1989, during a plant heatup, reactor coolant system (RCS) backleakage through a safety injection system check valve occurred three times. Following each occurrence the valve was restated by injecting water through the valve into the RC$ using a High Pressues Safety injection pump. Leakage was returned to within allowable limits and the plant heatup continuad. On June 27, 1989, a plant cooldown was performed due to an unrelated problem. While shutdown, the check valve that had leaked was disassembled and inspected. Two ro11 pins which connect the valve disc to the valve disc shaft, making them one integral part, were found missing. This ellowed a misalignment of the seating surfaces of the valve resulting in leakage as the RCS was pressurized. Based on these findings, another check valve of the same design was also disassembled and inspected. Both rollpins were present, however, one ro11 pin was found cracked and loose. The ro11 pins were replaced in both valves and the valves reassee-blod. A plant heatup was commenced and on July 3, 1989, a satisfactory leakage test was performed for each valve. The cause of the missing ro11 pins could not be deterstned. A metallurgical analysis of the cracked ro11 pin has been performed. Ir.spections of other check valves similar in design have been completed.

, . , , I Form 1062.015 BRC Fore 366A U.$. Nuclear Regulatory Coemission

-(9083)' Approved OMB No. 31bO-0104 i Expires: 8/31/85 LICENS(( [ VENT REPORT (LtR) TEXT CONTINUATION i FACILITY NAME (1) IDOCk(1 NUMBER (2) l t(R NUMB [R (6) l PAG [ (3) l l 1 l $equentiell lReviston!

Arkansas Nuclear One, Unit Two l 1.Yearl i Number I I Number i 10161010101 31 6f 81 81 91--I 01 Il ti--t 01 Il0!!!0F1018 -

7tK1 (If more space is required, use aeditional NRC f em 366A's) (17)

A. Plant $tatus At the time of occurrence of this event, Arkansas Nuclear One, Unit Two (ANO 2) was in Mode 4 (Hot

$hutdown), with Reactor Coolant $ystem (RC$) [AB) temperature approximately 276 degrees Fahrenheit and RC$ pressure approximately 385 psia. A plant heatup was in progress to return the unit to power operations following a maintenance outage to repair a leaking flange on the RC$ high point vent system.

B. Event Description During cold shutdown conditions reactor decay heat removal is accomplished by aligning the Low Pressure $afety injection (LPSI) (BP) system in a shutdown Cooling ($DC) configuration and circu-lating reactor coolant tforough a heat exchanger which is cooled by service water (BI). Suction is taken from the RCS hot leg piping and the coolant is returned to the core through four LP11 system injection headers (one header is connected to each RC$ cold leg). The boron concentration in the coolant is maintained at a sufficient level to ensure required reactor shutdown margins. During a plant heatup, after securing from the $DC mode (at about 290 psis RCS pressure) and following realignment of the LPSI system in the emergency core cooling configuration, the system piping is flushed with borated water from the Refueling water Tank (M) (TK). A recirculation flowpath is established by operating a LP$! pump with suction supplied from the RWT and returning water to the RWT through the $afety Injection Tank ($11) (BQ) drain line (see Figure 1). The headers are flushed one at a time by opening the appropriate $1T drain valves. This ensures the boron concen-tration in the headers is approximately the same as the concentration in the RWT. ($hutdown RCS boron concentration is usually less than the minimum RWT boron concentration of 2600 ppe.)

Oa June 26,1989, at 1818 hours0.021 days <br />0.505 hours <br />0.00301 weeks <br />6.91749e-4 months <br />, with RCS pressure approximately 345 psis, after SDC was removed from service, a flush of the LP$I system piping was commenced. At approximately 1915 hours0.0222 days <br />0.532 hours <br />0.00317 weeks <br />7.286575e-4 months <br />, while flushing the 'C' header, control room operations personnel observed a rapid decrease in pressura 12er water level at an estimated rate of approximately 20 spa. The LPS! header flush was secured by stopping the LPSI pump, closing the motor operated isolation valve (M0V) in the return to the RWT (2CV-5082) and closing the 'C' $1T drain vs1ve (25V-b041). The pressuriser water level decrecse stopped and began to increase as the charging system restored water level. Pressuriser water level was allowed to stabilize and the 'C' LPS! header flush recommenced in order to deter-eine the cause of the initial pressuriser water level decrease. Again, pressuriter water level decreased and the LP51 header flush was secured. At this time, en abnomally high pressure was indicated on the pressure indicator (2P15-5040) located on the low pressure side of safety injec-tion check valve 251*15C [8Q-f NV), indicating that backleakage from the RC$ through the check valve was occurring. The applicable Technical specification Action $tatement for excessive RCS leakage through the check valve was entered.

In an attempt to seat 25116C, a High Pressure $4fety Injection (HPSI) (BQ) pump was started and a HPSI MOV was throttled open to in.1ect borated water into the RC$ from the RWT through the leaking check valve. When the HP$1 pump was secured and the MDV was closed, the pressure on 2P35-5040 remained below RC$ pre 6sure indicating the check valve had seated. The LPSI header flush valve alignment was reestablished to create the same system alignment that was present when the valve was identified as leaking initially, and pressurifer water level did not decrease. Also, the pressure observed on 2P!$@40 indicated the valve had reseated and was not leaking. The LP51 header flush was secured and the Technical Specification Action Statement was exited at approxia mately 2125 hours0.0246 days <br />0.59 hours <br />0.00351 weeks <br />8.085625e-4 months <br />. The plant heatup continued and at about 2200 hours0.0255 days <br />0.611 hours <br />0.00364 weeks <br />8.371e-4 months <br />. Mode 3 (Hot $tandby) was entered.

At 2156 hours0.025 days <br />0.599 hours <br />0.00356 weeks <br />8.20358e-4 months <br />, a HP$1 pump was started and a smal) amount of makeup water was added to the SITS to increase water level in the tanks. At 2206 hours0.0255 days <br />0.613 hours <br />0.00365 weeks <br />8.39383e-4 months <br />, the HPS! pump was secured. The $1Ts were unisolated (tank outlet MOV's opened) and placed in service prior to RCS pressure rosching 690 psia. At approximately 2340 hours0.0271 days <br />0.65 hours <br />0.00387 weeks <br />8.9037e-4 months <br />, 251 15C was identified to be leaking again as indicated by the pressore on 2PIS-5040. RCS pressure at this time was approximately 784 psia. The Technical Specification Action Statement for RCS leakage through the check valve was again entered. On June 27,1989, at 0020 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, the 'C' 51T outlet valve (2CV-5043) was closed. At 0023 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />, a HP11 pump was started again and used to inject borated water into the RCS through 251 15C in an attempt

Firm 1062.018 NRC Fem 366A U.S. Nuclear Regulatory Comeission (l'83) Approved OMB No. 3160 0104 Expires 8/31/86 LICEN$(( (VENT REPDRT (LER) TEXT CONTINVATION FACILITY NAME (1) lDOCAtt NUMB &R (2) l ((R NUMBER (6) l PAGE (3) 1 l l 16eguentiall l Revision l Arkansas Nuclear One, Unit Two l l Yearl I Number f l Number l 10151010101 31 6f 81 81 91--I 01 It 21 -I of 1101310Fl018

' TtxT (if more space is required, use additional NRC f om 366A's) (17) to seat the check valve. When the HP$! pump was secured and the HP$1 header MOV closed, the 'C'

$!T drain valve and the MOV (2CV 60el) to the Reactor Orain Tank (RDT) [WD TK) were opened to vent the line between the $1T outlet valve and 2$1 15C. Pressure on 2P!$ 6040 decreased to approx 1-mately 60 psia indicating the check valve was probably seated. At 0029 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br />, the 'C' $17 outlet valve was reopened. Pressure indicated by 2PIS 6040 increased to approximately 760 psia indicat-ing that backloakage through 251 1bc was occurring again.

At 0122 hours0.00141 days <br />0.0339 hours <br />2.017196e-4 weeks <br />4.6421e-5 months <br />, with RC$ pressure approximately 1070 psia, the 'C' $1T outlet valve was closed again. As in earlier attempts to seat 2$116C, the HP$1 system was aligned to inject borated water into the RC$ through the check valve. Af ter the HP$1 pump and alignment were secured the drain valve to the ROT was opened to vent the header, however, the pressure on 2Pl$ 5040 indicated 1 the attempt to seat the check valve was unsuccessful. At approximately 0130 hours0.0015 days <br />0.0361 hours <br />2.149471e-4 weeks <br />4.9465e-5 months <br />, mechanical maintenance personnel entered the containment building. These personnel tapped on the bonnet of '

251 16C with a brass rod in an attempt to help seat the valve. At 0162 hours0.00188 days <br />0.045 hours <br />2.678571e-4 weeks <br />6.1641e-5 months <br />, two HP$1 pumps were r started, both HP$I header MOVs to the 'C' loop were opened And borated water was injected into the RCS through 2$1 16C. &cth pumps were secured and the MOVs closed. 251 15C appeared to have seated I by a pressure of approximately 60 psia indicating on 2P2$-6040. At 0206 hours0.00238 days <br />0.0572 hours <br />3.406085e-4 weeks <br />7.8383e-5 months <br />, the 'C' $1T cutlet .

valve was opened and the pressure indicated by 2Pl$ 6040 increased as expected to approximately 600 psia. (Nomal operating pressure maintained by the nitrogen pressure on $1T is 612112 psig.) RCS pressure at this time was approximately 1200 psia. Also at this time, the Technical Specification Action Statement for RCS leakage was exited. The heatup of the RCS was continued.

On June 27,198g, at 0705 hours0.00816 days <br />0.196 hours <br />0.00117 weeks <br />2.682525e-4 months <br />, RCS average temperature was approximately 645 degrees and RCS pressure about 2250 psia. At 0730 hours0.00845 days <br />0.203 hours <br />0.00121 weeks <br />2.77765e-4 months <br />, control Room Operations personnel noted that the con-tainment building sump water level had increased approximately twenty percent over a three hour period. At 0910 hours0.0105 days <br />0.253 hours <br />0.0015 weeks <br />3.46255e-4 months <br />, a plant cooldown was commenced due to an estimated RCs unknown leakrate of about 9.77 ppe. At 0920 hours0.0106 days <br />0.256 hours <br />0.00152 weeks <br />3.5006e-4 months <br />, a flange located on the reactor vessel head high point vent system in the containsont was identified to be the source of the RC$ leakage. The RCS leakrate was monitored and ditt not e=ceed 10 gpa throughout the RCS cooldown. At 1240 hours0.0144 days <br />0.344 hours <br />0.00205 weeks <br />4.7182e-4 months <br /> on June 27, 1989 Mode 4 (Hot Shutdown) was entered, and at 1616 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.14888e-4 months <br /> Mode 5 (Cold $hutdown) was achieved.

While in cold shutdown 2$1*1bC was disassembled and inspected. The inspection revealed that two ro11 pins used to connect the valve disc to the disc shaft were missing. Due to the problems found when 251 15C was disassembled, another similar check valve, 2$1-16A was opened for inspection.

Although both ro11 pins were found to be installed in this valve, one rollpin was found loose and cracked, allowing the rollpin to slide back and forth. This discrepancy did not affect proper .

valve operation, since tha disc was still edequately secured to the shaft. No other problems were '

identified, during these inspections.

C. Safety Significance .

The design configuration of the AN0 2 safety injection system allows for continuous monitoring of RCS backleakage through the four check valves (25115A, B, C and D) installed in the safety injection hooders to each RC$ cold leg. A Control Roca pressure instrument with indication and audible alare is located on the low pressure side of each of the check valves. Each time check i valve 2$1-15C was noted to be leaking, the leakage flowpath was isolated and the check valve was l' subsequently resented. Also, RC$ pressure and pressurizer water level were restored and adequate-ly maintained. High pressure to low pressure system interfaces were maintained during each leakage event by redundant check valves in the LPSI and HP$1 injection headers. The capability of the check valve to open, if required for HP$1 ce LPSI injection, was not affected by the missing rollpins. In all, no significant impact on plant safety occurred as a result af 251 15C backlockage.

The potential safety concern associated with this event is related to the possibility for over-pressurization of low pressure systems which are connected to the high pressuro reactor coolant system and which penetrate the containment building. The Reactor Safety Study (R$$), Wash-1400, identified an intersystem loss of coolant accident (LOCA) in a PWR as a significant contributor to risk associated with core melt accidents. This type of accident (designated as EVENT V) involved system designs containing two in-series check valves isolating the high pressure RCS from system piping with a lower design pressure f e.g. , LP$1). The scenario which leads to the EVENT V acci-dont is initiated by the failure of these check valves to function at, a pressure isolstion barrier This can cause an overpressurization and rupture of the low pressure piping resulting in a LOCA

Fore 1062.01B MRC Form 366A U.$. Nuclear Regulatory Commission (9*83) Approved DMB No. 3150*01D4 Empires: 8/31/85 i LIC[N$([ [Y[NT REPORT (LER) 1tKT CONTINUATION FACILITY NAME (1) (DOCKET NJMBER (2) l LIR NJMBER (6) l PAG [ (3)~ '

l l l 16equentiall IRevisioni Arkansas Nuclear One, Unit Two l l_Yearl 1 Number I i Number l 10151010101 31 61 81 81 91*-I of 11 21**I of 1101410Ft018 TLXT (if more space is required, use additional NRC f orm 366A's) (17) that bypasses containment. A review of the AN0*2 system design shows that an EVENT V isolation valve configuration (e.g., (1) two check valves in series, or (2) two check valves in series with a MOV) does exist and two piping system are of concern. The HPSI and LP$I systems are connected to the RCS by a single common line to each of the cold legs. Both the HPSI and LP$1 systems have two check valves 6ed a motor operated valve in series with the high pressure / low pressure inter

• face on the upstream side of the MOVs (see Figure 1). (Although a high pressure / low pressure interf ace also exist on the $1T outlet lines and the potential exists for over pressurization of this piping, this is not considered to be an (VENT V valve configuration because the piping does  ;

not penetrate the containment building.) '

During the check valve backleakage events which occurred on June 26, 1989, 251*16C was successfu1*

ly resented following each occurrence of backloakage. However, based upon the observed response of the valve during the events combined with the subsequent discovery that the rollpins were missing, it is probable that the valve would not have ressated and prevented backleakage if it were ever challenged to open. During plant operation, reasonable conditions can be postulated to occur which would require the valve to open and then subsequently close. For example, certain sizes of main steam line breaks or malfunctions of plant equipment may cause an RC$ overcooling transient and depressuritation to the setpoint for automatic actuation of HPSI which could open the valve as water is injected into the RC$. Subsequently, RC$ pressure may recover and increase back to normal operating system pressure (approximately 22$0 psia). Under such a postulated scenario protection of the high pressure / low pressure system interface would be dependent upon satisfactory operation of the redundant single check valve in each piping system. Under worst case conditions if this check valve were to also fail or leak excessively, overpressurization of portions of the HP$1 and/or LPSI system could occur potentially creating an Event V accident.

It is important to note that the discussion above is intended to represent a worst

• case scenario.

Although the consequences of such an event would be significant, the probability of occurrence at this facility is considered to be small. Specifically, at AN0*2, as indicated on Figure 1, the HPSI header 1 piping upstream of the injection MOVs has a design pressure of 2486 psig, There*

fore, even a concurrent f ailure of the redundant HP$1 check valve (s) under the conditions postua lated above would not be expected to overpressurize this piping. HPSI header 2 piping upstream of the injection MOVs has a design pressure of approximately 1950 psig. Exposure of this piping to pressures greater than design does not inherently imply a postulated rupture of the piping due to the margins incorporated as part of the design of piping systems. The LP$1 piping upstream of the -

injection M0Vs has a design pressure of 500 psig, therefore, this piping would be most susceptible to potential failure due to overpressurization. However, the AN0-2 Technical $pecifications require periodic monitoring and measurement of backleakage through the redundant check valves protecting this piping (2$3-14A, B, C and D) and provide specific limits on allowable leakage thereby providing a high level of confidence of the functional capability of these valves to prevent backloakage.

D. Root Cause The safety injection check valves (2$1*15A, 8. C and D) are designed with a swinging disc connect

• ed by two rollpins to a largo diameter shaft, which in turn, rotates in hardened stainless steel bushings. The shaft ends which fit into the bushings are asymmetrical to the shaft. The ro11 pins are used to attach the disc are to the shaft so they will move together as one integral piece.

When 2$1 15C was disassembled and inspected, ro11 pins were found to be missing and also the disc shaft had rotated 160 degrees from its proper position. Since the shaft has asymmetrical ends, the disc are aovement with the shaf t located 180 degrees out resulted in misalignment of the seating surfaces and valve leakage.

The root cause of the missing ro11 pins in 2$115C could not be conclusively determined. A review of the maintenance history records for the check valve indicated that the ro11 pins had been removed when the valve was disassembled during initial plant construction in 1977. The valve internals had been removed in order to perform the initial RC$ hydrostatic test. It is known that the valve internals (disc, shaft, etc.) were reinstalled following this evolution and the records indicated that the ro11 pins had also been reinstalled. Bssed on this information, it is suspected at this time that the rollpins subsequently failed due to some mechanism and became dislocated.

i Form 1062.018 NRC Fem 366A U.S. Nuclear Regulatory Commission 4 (9 83) Approved OMB No. 3150 0104 '

Expires: 8/31/85 I LICIN$(( [YENT REPORT (LER) TEXT CONTINUATION j FACILITY M ME (1) lDOCAli NUMBLR (2) l Lf R WMBER (6) l PAGE (3)

I l 1 15eopentiell l Revision l Arkansas Nuclear One, Unit Two l L Yearl i Number f i Number l 1015101010! 31 6I 81 81 91 I 01 11 21--I Of Il015!0F1018 1 T[KT (If more space is required, use additional NRC Form 366A's) (17) j l

A metallurgical analysis of the cracked ro11 pin removed from check valve 2$115A was perfomed by I tabcock and Wilcox (SW). The evaluation indicated the rollpin material was probably heat treated type 420 stainless steel. This is the material that was expected to be identified. The failure consisted of multiple axial and circumferential intergrannular cracks. The results of the analysis indicated that the failure mechanism was believed to be intergrannular stress corrosion cracking.

As a contributing factor to the failure, it is suspected that the ro11 pin might not have been properly heat treated during the manuf acturing process.

E. Basis for Reportability The discovery of the missing ro11 pins from 2$115C was considered to be a condition that was outside the design basis of the plant and reportable per 10CFR$0.73(a)(2)(11)(8). The design basis of the plant includes design provisions such that for postulated credible events single failures of components will not result in the loss o' the capability of a system to perform its safety function. With respect to the discrepancy with check valve 251 150, the applicable safety function of importance is the maintenance of adequate isolation barriers between the high pressure RCS and the connected lower pressure systems (i.e., HP51, LPSI and $1T outlet piping) to ensure the low pressure systems are not exposed to pressures greater than their design pressures during '

postulated events.

The ANO-2 system design incorporates two redundant check valves located in series (25115C and 251 13C or 251-14C) in each affected piping system. Due to the missing ro11 pins in 25115C it could not be assured that this valve would function properly as an isolation barrier during certain plant conditions. Therefore, for a limited period of time the plant was susceptible to a loss of this safety functior if a single failure of either of the redundant check valves were to  ;

occur.

The manual actuations and use of the NPSI pumps and MOVs to inject water through 2$115C during e* forts to rescat the valve and stop the backleakage were considered to be manual actuations of an Engineered Safety Feature that were not part of a preplanned sequence during testing or reactor operation and are reportable per 10CFR50.73(a)(2)(1v).

ANO 2 Technical Specification 3.4.6.2 specifies a maximum allowable value for backleakage through certain safety injection system check valves including valve 251-15C. If leakage greater than the allowable value occurs, Technical Specification 3.4.6.2 Action Statement 'C' requires isolation of ,

the high pressure portion of the affected system from the low pressure portion within four hours by the use of at least two valves in each high pressure line having a non functional valve.

l 1 solation valves may include check valves for which the leakage rate has been verified, manual

, valves or automatic valves. If manual or automatic valves are used to comply with the isolation l requirements of the Action Statement the Specification requires tagging the valves closed to preclude inadvertent opening. Considering the discovery that the rollpins were not installed in the valve internals and the failure of the valve to limit backleakage within the allowable limits tluring the plant heatup, on June 26, 1989, it was concluded that 251 15C was not operable (i.e. ,

non-functional). The requirement of Technical Specification 3.4.6.2 to isolate the valve witnin

( four hours was not met, therefore, this event is also considered to be reportable per

( 10CFR50.73(a)(2)(1)(B), as a condition prohibited by the plant's Technical Specifications.

The NRC was notified of the occurrence and details of these events per the requirements of 10CFR50.72(b)(2)(1) and 10CFR50.72(b)(2)(11) on August 4, 1989, at 1620 hours0.0188 days <br />0.45 hours <br />0.00268 weeks <br />6.1641e-4 months <br />.

The length of time between occurrence of the events discussed in this report and the submittel date for this report is greater than 30 days as specified in 10CFR50.73. Initially, the malfunc-

[ tion and backloakege through check valve 25!*15C was evaluated and detemined not to constitute a l~ reportable occurrence. However, Arkansas Power and Light Company elected to submit e voluntary l report due to the potential generic applicability of the event and recent industry problems with l safety related check valve malfunctions. Based on the additional information concerning the cause of the check valve failure which was obtained following disassembly of 2SI 15C, and detailed

( reviews performed while developing the voluntary report, reportability of the event was reevalu-ated and it was concluded the occurrence should be detemined reportable per the criterion dh*

cussed above.

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Form 1062.01B hhc fem 366A U.$. Nuclear Regulatory Commission (9 83; Approved OMB No. 3150-0104

[xpirest B/31/85 LIC[N$(( [V[WT R[ PORT (L[R) 1[KT CDNTINUATION IACIL31Y hAML (1) (DOCA [T NUM8[R (2) l L1R NUMMR (O l FAGL (3) 1 l l 15equentiell ikewision)

Arkansas Nuclear One, Unit Two l I Yeart i Number i 1,3 mber i 10151010101 31 61 81 el 91 -I 01 i t 21--I Of 1101610F1018 1[xT (If more space is required, use additional Nhc f ore 366A's) (17)

F. Corrective Actions The ro11 pins in 2$115C and the cracked rollpin in 2$1*15A were replaced, and the valves reassem-bled. Proper operation of the valves was verified when a leak test was performed on the check valve during the plant heatup on July 3,1989.

With respect to the loop check valves (25115B and D) that were not inspected during the outage in June 1989, several factors were evaluated in reaching a decision to defer internal inspection of these valves. A review of the operational history of these valves did not reveal any significant indication of backleakage through the valves. Monitoring for the presence of backleakage is conducted during each plant heatup and periodic measurement of valve backleakage is performed.

The pressure indicators located on the low pressure side of the valves also provide continuous monitoring capability for detection of valve backloakage. These valves are located in areas of relatively high radiation levels warranting consideration of the personnel exposures necessary to perform maintenance on the valves. Also, the short period of plant operating time remaining until the next refueling outage was scheduled to begin was considered to be a factor.

Futher investigations revealed that the check valves located on the $1T outlet lines (25116A, B, C and D) were of the same design as 251 15C. The maintenance and operational history related to these valves was reviewed. Based on these reviews it was determined that no significant backleakage had been observed through these valves during previous plant operation. Additionally, the valves were noted to be included in the plant's Inservice Testing Program (!$T) and have been ,

opened and inspected several times during previous refueling outages. Although, the IST inspec- I tions were orientsd primarily toward verification of the valve's capability to stroke to a full open position if required and did not specifically require an inspection of the rollpins, there is a level of confidence that any significant degradation of the valves functional capability to prevent backleakage would have been detected during these inspections. Based on these considera*

tions and other factors (e.g., environmental and operating conditions of the $1T outlet checks are significantly dif ferent than those of the 251 15 check valves), it was concluded that disassembly and inspection of these valves could also be deferred.

The location of other safety related check valves, manufactured by Atwood and Morrill Company, which are similar in design to the 2$1 156 with the use of ro11 pins, have been identified. A program to periodically inspect some of these valves already exists.

Evaluations are to be conducted regarding the failure to initially recognize the significance of the check valve perfomance behavior on plant operation and the associated ?oportability implications.

During the 2R7 refueling outage (September 25, 1989

• November 20, 1989) check valves 251 158, 251 150 and the $1T outlet check valves (2$1 16A,B,C and D) were disassembled and inspected, in each of the check valves the ro11 pins were found installed. One rollpin in 251-16A was found cracked, however, valve operability was not edvarsely offacted due to the ro11 pins being installed.

Both of the ro11 pins when removed from check valve 2$1*15B were found intact, however, several hairitne cracks were identified running along the length of both pins. Based upon a recommendation from BW and discussions with the valve manufacturer, the ro11 pins were replaced with grooved pins made from 316 stainless steel and tack welded in place. The original ro11 pins were a type 420 stainless steel material. The stainless steel material was changed because hardened stainless steels are particularly susceptible to stress corrosion cracking and hydrogen embrittlement in an aqueous environment.

Based upon the findings of the inspection of the ro11 pins removed from 2$1 158 and 251 150 (i.e.,

the ro11 pins in both valves were found installed, however, with small hairline cracks) and Engineering judgement ANO-2 management decided that the rollpins which had been installed in  ;

251 15A and 251 15C in June 1989 would last until the next refueling outage (2R8). There fore ,

2$1-15A and 251-15C were not opened for inspection or ro11 pin replacement during 2R7 refueling outage.

Two other check valves manufactured by Atwood and Morrill Company (2FW-5A and 2BS 1A), which are similar in design to the 25115s with the use of rollpins, were disassemblied and inspected.

There were no discrepancies identified during the inspections. Other valves similar in design which are manufactured by Atwood and Morrill Company were not inspected due to the fact stress corrosion cracking would not be expected to occur in the environment in which the valves are located.

.. l teht form SEA Form 1062.01B !

U.S. Nuclear Regulatory Commission

[ (9 43) Appr$ved DOS No. 3160 0104

• l Expires: t/31/86 .

LIC[N5f t (VENT REPORT (LER) TEKT CONTINUATION f FACILITY NAME (3) 100CAff NUMBER (2) l Llk NultiR (6) l PAGE (3) l l l 15equentiell IRevisient l - Arkansas Nuclear One. Unit Two l l_Yearl I Number I i Number i l'- 10f61010101 31 61 8f 81 91--t Of 11 ti- t 01 2101710F1018  :

( TEXT (If more space is required, use socitional NRC Fors 3%A's) (17)

G. Additional Information A steller event, which occurred at AND-1, related to RC$ backle&kege due to the Delfunction of a safety reisted check volve was previously reported in LER 60-313/89 004-00 (ICAN068911).

e Energy Industry loontification System (t!!$) codes are identified in the text es [XX).

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Form 1062.01B NRC Foro 366A U.$. Nuclear Regulatory Commission (9*83) Approved Oft No. 3150-0104 '

LICENSEE EVENT REPORT (LER) TEXT CONTINUATION FACILITY NAME (1) l DOCKET NL9tER (2) l LfR NUM8[R (6) l PAGE (3) l l l l$equentiall l Revision!

• Arkansas Nuclear One. Unit Two l l_Yearl i Number l Number l i 10161010101 31 61 81 81 91--I 01 Il 21-- 01 Il01010F1018 ,

TEXT (If more space is required, use additional NRC Fors 366A's) (17)

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