05000446/LER-2006-001, Regarding Condition Prohibited by Technical Specifications

Regarding Condition Prohibited by Technical Specifications

ML062560047
Person / Time
Site:	Comanche Peak
Issue date:	08/24/2006
From:	Blevins M, Madden F TXU Power
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CPSES-200601627, TXX-06139 LER 06-001-00
Download: ML062560047 (7)

LER-2006-001, Regarding Condition Prohibited by Technical Specifications

Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(i) 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded 10 CFR 50.73(a)(2)(viii)(A) 10 CFR 50.73(a)(2)(ii) 10 CFR 50.73(a)(2)(viii)(B) 10 CFR 50.73(a)(2)(iii) 10 CFR 50.73(a)(2)(ix)(A) 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications
4462006001R00 - NRC Website

text

TXU Power TXU Power Comanche Peak Steam Electric Station P. 0. Box 1002 (E01)

Glen Rose, TX 76043 Tel: 254 897 5209 Fax: 254 897 6652 mike.blevins@txu.com Mike Blevins Senior Vice President &

Chief Nuclear Officer Ref: #10CFR50.73 CPSES-200601627 Log #TXX-06139 August 24, 2006 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555

SUBJECT:

COMANCHE PEAK STEAM ELECTRIC STATION (CPSES)

DOCKET NO. 50-446 - LICENSEE EVENT REPORT 446/06-001-00 CONDITION PROHIBITED BY TECHNICAL SPECIFICATIONS Gentlemen:

Enclosed is Licensee Event Report (LER) 06-001-00 for Comanche Peak Steam Electric Station Unit 2, "Condition Prohibited by Technical Specifications."

This communication contains no new licensing basis commitments regarding CPSES Units 1 and 2.

Sincerely, TXU Generation Company LP By:

TXU Generation Management Company LLC Its General Partner Mike Blevins FredW. Madden Director, Regulatory Affairs RJK Enclosure c -

B. S. Mallett, Region IV M. C. Thadani, NRR Resident Inspectors, CPSES A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• South Texas Project

• Wolf Creek 0V2 0/

Enclosure to TXX-06139 NRC IrORM 366 UI'. N'UCLEARREGULA IORY COMMISSION APPROVED BII O( B INO. 3150-0104 EXPIRES 06(30,2007 (6-2004)

Estimated burden per re'ponse to comply with this mandatory collection request: 50 hour5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br />.

Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Records and tOIA'Privacy Service Branch (T-5 1:52). U.S. Nuclear Regulatory Commission, Washington. DC 20555-0001 or by intenect e-mail to htifo:ollectls'nrc.gov. and to the Desk Officer, Office of Infortnation and Regulatory Atfaits, NUO1t-10202 (3150-0104). Office of M~anagetnent LI CENSE E EVENT REPORT (LER) n"n...

goao A..

OI00(,0,,Ofio"a,*n, andi Budget. Washsington. DC 20503. Ifa mcans used to impose an information collection does not display a currently valid OM1 control number, the NRC may not conduct or sponsor. and a person is not required to resrxsod to. the information collection.

1-actlty Name I1)

Docket Numtber (2)

Page (3)

COMANCI IE PEAK STEAM ELECTRIC STATION UNIT 2 05000446 1 OF 6 I tIe (4)

CONDITION PROHIBITED BY TECHNICAL SPECIFICATIONS Event Date 15)

LIR Number 16)

Reptirl tate (7)

Other Factlhtics Involved tN)

Month Day Year Year Sequential Revitson Month Day Year t-aclhty Name Docket Nttmbers I

Number Number N/A 05000 06 25 2006 006 001 H 00 08 24 105000 Operatge hls report ii submitted pursuant to the requirements olf10 L1-R : (Check all that apply) (11) 20.2201(b) 20.2203(a)(3)(i) 50.73(a)(2)(i)(C) 50.73(a)(2)(vii)

Pao..r 20.2201(d) 20.2203(a)(3)(ii) 50.73(a)(2)(ii)(A) 50.73(a)(2)(viii)(A)

L tl (1) 100%

20.2203(a)(1I) 20.2203(at)(4) 50.73(a)(2)(ii)(l3) 50.73(a)(2)(viii)(B) 20.2203(a)(2)(i) 50.36(c)(2)(i)(A) 50.73(a)(2)(iii) 50.73(a)(2)(ix)(A) 20.2203(a)(2)(ii) 50.36(c)(l )(ii)(A) 50.73(a)(2)(iv)(A) 50.72(a)(2)(x) 20.2203(a)(2)(iii) 50.36(c)(2) 50.73(a)(2)(v)(A) 73.71(a)(4) 20.2203(a)(2)(iv) 50.46(a)(3)(ii) 50.73(a)(2)(v)(B) 73.71 (a)(5) 20.2203(a)(2)(v) 50.73(a)(2)(i)(A) 50.73(a)(2)(v)(C)

X OTHER 20.2203(a)(2)(vi)

X 50.73(a)(2)(i)(B) 50.73(a)(2)(v)(D)

Specify in Abstract below or in =

SUMMARY OF THE EVENT, INCLUDING DATES AND APPROXIMATE TIMES On June 25, 2006 at 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br />, a Plant Equipment Operator (PEO) (utility, non-licensed) observed an oscillation in the air pressure supplied to the actuator of atmospheric relief valve (ARV) 2-PV-2328 [EIIS:(SB)(ACC)(RV)] on the #4 Main Steam [EIIS:(SB)] line.

While the pressure reading was within specification, this oscillation was considered abnormal and was reported to the Control Room. At this point, troubleshooting by licensee staff commenced to determine the cause of the abnormal pressure oscillation.

On June 26, 2006 at 1230 hours0.0142 days <br />0.342 hours <br />0.00203 weeks <br />4.68015e-4 months <br />, while performing air drop testing of the accumulator check valves for ARV 2-PV-2328 to verify component operability, licensee staff observed air pressure dropping significantly as soon as the Instrument Air isolation valve (2-PV-2328-AS I) was closed. The isolation valve was reopened, valve 2MS-0705 (SG 2-04 ATMOS RLF VLV AIR ACCUM 2-04 ISOL VLV) [EIIS:(LD)(ISV)] was cycled closed and then opened to verify its position. Due to the assumed leak in the air supply to the actuator, the ARV was declared inoperable and Technical Specification 3.7.4 was entered.

Technical Specification 3.7.4, CONDITION A (One required ARV line inoperable) requires that the inoperable ARV line be restored to OPERABLE status within 7 days or the Unit must be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 4 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

NRC; 1F01M 366A (I-200i

Enclosure to TXX-06139 N RC: FIM 366A U.S. NUCLELAR REG(UIA I ORY COMMISSION (1-20) 1)

LICENSEE EVENT REPORT (LER)

Facility Nanic (I)

D)ocket LER Number (6)

I Page(3)

Year S qil an COMANCIIE PEAK STEAM ELECTRIC STATION UNIT 2 M

sti N mkr 05000446 2006H 001 H 00 3 OF 6 NARRA IS1I (It more space is rfqulr*Al use additional copies of NRC Fomr 366A) (17)

On June 26, 2006 at 1654 hours0.0191 days <br />0.459 hours <br />0.00273 weeks <br />6.29347e-4 months <br />, troubleshooting by plant staff had eliminated either the Instrument Air system tubing or the ARV itself as the source of an air leak, and other potential sources of air leakage were considered. After capping the Current to Pressure (I/P) converter (2-PV-2328-IP), the pressure oscillations disappeared and the I/P converter was replaced.

However, upon restoration of the ARV line on June 26, 2006 at 2250 hours0.026 days <br />0.625 hours <br />0.00372 weeks <br />8.56125e-4 months <br />, the pressure oscillations returned and troubleshooting recommenced.

On June 27, 2006 at 0509 hours0.00589 days <br />0.141 hours <br />8.416005e-4 weeks <br />1.936745e-4 months <br />, plant staff deternmined that valve 2MS-0705 was the cause of the restriction between the ARV actuator and its accumulator. A review of past operating history related to 2MS-0705 was conducted and the valve was last closed on June 8, 2006 for maintenance and most likely did not reopen when the system was restored due to the stuck valve disk. This condition isolated the ARV from its associated air accumulator, rendered the ARV line inoperable, and was determined to be a reportable condition due to the ARV line being inoperable for a period greater than that allowed by the Technical Specifications.

On June 27, 2006 at 1536 hours0.0178 days <br />0.427 hours <br />0.00254 weeks <br />5.84448e-4 months <br />, after replacing valve 2MS-0705 and completing all retests, the ARV line was declared OPERABLE.

E.

THE METHOD OF DISCOVERY OF EACH COMPONENT OR SYSTEM FAILURE., OR PROCEDURAL OR PERSONNEL ERROR While performing routine plant rounds, an operator (utility, non-licensed) observed an abnormal oscillation in the air pressure supplied to the actuator of atmospheric relief valve (ARV) 2-PV-2328. Subsequent troubleshooting determined that valve 2MS-0705 was the cause of the restriction between the ARV actuator and its accumulator.

II.

COMPONENT OR SYSTEM FAILURES A.

FAILURE MODE, MECHANISM, AND EFFECT OF EACH FAILED COMPONENT The failed valve, 2MS-0705, was sent to an off site investigator (Southwest Research Institute) for failure analysis. The investigator determined that this valve sticking closed was caused by a manufacturing defect and a misalignment between the seat and disk. This misalignment resulted in the smearing and deformation of the metal on engaged surfaces of the body and the disk.

NR(: 0KM t6bA,(l1-2U01)

Enclosure to TXX-06139 NRC tORM 366A U.S. NUCLEAR Rt:GU:LAIORY COMMISSION (I -200 I LICENSEE EVENT REPORT (LER)

Facihtiy Name (1)

Domck LLR Numb crr(,)

(Pag(3)

Year a

Seq Rcs on COMANCHE PEAK STEAM ELECTRIC STATION UNIT 2 N

Numr 05000446 2006H 001 H O 4 OF 6 NSRRA 11VT (If more space is required. usc additional copics of NRLC lorm 3.66A) (17)

B.

CAUSE OF EACH COMPONENT OR SYSTEM FAILURE The failure evaluation report concludes that there was a misalignment of the disk with respect to the body, and that flash around the outlet port (present when the valve was new) also appeared to play a significant role in immobilization of the disk in the closed position. The report suggests that repeated closure of the misaligned disk led to accumulated damage that ultimately immobilized the disk in the closed position.

C.

SYSTEMS OR SECONDARY FUNCTIONS THAT WERE AFFECTED BY FAILURE OF COMPONENTS WITH MULTIPLE FUNCTIONS Not applicable - No failures of components with multiple functions have been identified.

D.

FAILED COMPONENT INFORMATION

Nomenclature Manufacturer Model Number 1/2" Globe Valve Kerotest CP-4TE-D22S/2 III.

ANALYSIS OF THE EVENT

A.

SAFETY SYSTEM RESPONSES THAT OCCURRED Not applicable - No safety system responses occurred as a result of this event.

B.

DURATION OF SAFETY SYSTEM TRAIN INOPERABILITY The Unit 2 ARV (2-PV-2328) was inoperable from June 8, 2006 till June 27, 2006, a period of approximately 19 days.

C.

SAFETY CONSEQUENCES AND IMPLICATIONS OF THE EVENT An ARV is considered OPERABLE when it is capable of providing controlled relief of the main steam flow and capable of fully opening and closing on demand using associated remote manual control. The automatic controls for the ARVs do not perform a safety function.

The ARVs provide a mnethod for cooling the unit to residual heat removal (RHR) entry conditions should the preferred heat sink via the Steam Dump System to the condenser not be available, as discussed in the FSAR, Section 10.3. This is done in conjunction with the Auxiliary Feedwater System providing cooling water from the condensate storage tank (CST). The ARVs may also be required to meet the design cooldown rate during a normal cooldown when steam pressure drops too low for maintenance of a vacuum in the NRC lORM 366A(l-2001j

Enclosure to TXX-06139 NR1( fORM 366A, U.5. N.L'.LAR RU;LA.AIOI(.

COMMISSION (I-2101I LICENSEE EVENT REPORT (LER)

I acilty Name (I )Docket L

Numblr (6)

Page(31 Y,,.r X

c COMANCIIE PEAK STEAM ELECTRIC STATION UNIT 2 0

4 Ne, Nuur E5000446 2006H 001 H 00 5 OF 6 NARRAIVIE (I1 more space is rcquired. use additional copies olNR.' form 3iMA) (17) condenser to permit use of the Steam Dump System. One ARV line for each of the four steam generators is provided. Each ARV line consists of one ARV, its associated remote manual controls and an associated block valve. The ARVs are provided with upstream block valves to permit their being tested at power and to provide an alternate means of isolation.

The ARVs are equipped with pneumatic controllers to permit control of the cooldown rate and are provided with pressurized air accumulators that, on a loss of pressure in the normal instrument air supply, automatically supply air to operate the ARVs. With 80 psig pressure, the air accumulators have sufficient capacity to operate the ARVs for the time required for Steam Generator Tube Rupture mitigation. The failure of the manual isolation valve (2MS-0705) to open would result in the loss of the accumulator back-up to provide this control capability for the associated ARV.

The design basis for the minimum relief capacity of the ARVs is established by the capability to cool the unit to RHR entry conditions and the capability to mitigate a steam generator tube rupture (SGTR). The design basis for the maximum relief capacity is established by the 10CFR100 limits for SGTR and the capacity of the MSSVs assumed in the accident analyses. The design rate of 50'F per hour is applicable for a natural circulation cooldown using two steam generators, each with one ARV. The unit can be cooled to RHR entry conditions with only one steam generator and one ARV, utilizing the cooling water supply available in the CST. In the safety analysis, the ARVs are assumed to be used by the operator to cool down the unit to RHR entry conditions for events accompanied by a loss of offsite power. Prior to operator actions to cool down the unit, the main steam safety valves (MSSVs) are assumed to operate automatically to relieve steam and maintain the steam generator pressure below the design value. For the recovery from a SGTR event, the operator is also required to perform a limited cooldown to establish adequate subcooling as a necessary step to terminate the primary to secondary break flow into the ruptured steam generator. The time required to terminate the primary to secondary break flow for an SGTR is more critical than the time required to cool down to RHR conditions for this event and also for other accidents. Thus, the SGTR is the limiting event for the ARVs. Four ARVs are required to be OPERABLE to satisfy the SGTR accident analysis requirements based on consideration of single failure assumptions regarding the failure of one or two ARVs to open on demand.

Since the normal Instrument Air supply was available for the duration in which 2MS-0705 was closed, it is concluded that the health and safety of the public was unaffected by this condition. This event has been evaluated to not meet the definition of a safety system functional failure per 10CFR50.73(a)(2)(v) in that this single component failure would not have prevented fulfillment of the safety function as discussed above.

NR.' FRI 366A (1 -2001)

Enclosure to TXX-06139 NRC fORMI 366A U.S. NtUCIEAR REGI.t.AIORY C(1OMISSION I1-200)

LICENSEE EVENT REPORT (LER)

Facility Name (I)

L)[xkct LLR Nun*cr (6)

PagIcl )

Year Sequential Resion COMANCIIE PEAK STEAM ELECTRIC STATION UNIT 2 0

Numbr Nme 05000446 2006 ool H 00 6 OF 6 NAIRAI'IVE. (If'more space is required, use additional copic% of NRC i-orm 366A) (17)

IV.

CAUSE OF THE EVENT

Evidence in the failure evaluation report suggests that the preexisting flash around the outlet port and repeated closure of the misaligned disk led to accumulated damage that ultimately immobilized the disk in the closed position. This combination of manufacturing defect and misalignment was not sufficiently gross to have caused an immediate failure of the valve. However, damage accumulated through use of the valve during normal operation until sufficient resistance existed to overcome the opening force of the spring.

V.

CORRECTIVE ACTIONS

The valve that failed (2MS-0705) is located in-line between the ARV air accumulator and the instrument air supply. This valve was replaced. Comanche Peak has a total of eight components in this same configuration. The remaining seven valves were verified by the system engineer to be operating correctly (not remaining closed). The verification was performed by a visual confirmation that the pressure indicators associated with each safety related accumulator were not exhibiting oscillations that were characteristic of a closed isolation valve as noted in this condition. The valves verified were I MS-0702, I MS-0703, I MS-0704, I MS-0705, 2MS-0702, 2MS-0703, and 2MS-0704.

As part of the site's corrective action program, CPSES Engineering personnel are developing a method to verify Kerotest valve position. The valves to be considered would be limited to those in applications where the failure to open would have an adverse impact on operability or the ability to mitigate loss of a safety function. In addition, the current "run-to-failure" Preventive Maintenance classification of these Kerotest valves is being reviewed to determine if it is adequate to prevent event recurrence.

VI.

PREVIOUS SIMILAR EVENTS

There have been no previous similar reportable events at CPSES in the last three years. However, among the approximately 500 Kerotest globe valves of similar design installed in both units at CPSES, there have been at least three previous non-reportable events in the last 6 years documented in the CPSES Corrective Action Program where a the valve has failed to open after being closed during an evolution. In each of these instances, the failure was immediately obvious due to the system response, the failed valve was replaced, and the condition was considered a low significance failure.

NRC II IRM3tN'Aj(I-2(101)