05000458/LER-2006-002, Re Loss of Safety Function of High Pressure Core Spray Due to Manual Deactivation

Re Loss of Safety Function of High Pressure Core Spray Due to Manual Deactivation

ML060930687
Person / Time
Site:	River Bend
Issue date:	03/27/2006
From:	Lorfing D Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
G9.25.1.3, G9.5, RBF1-06-0060, RBG-46551 LER 06-002-00
Download: ML060930687 (7)

LER-2006-002, Re Loss of Safety Function of High Pressure Core Spray Due to Manual Deactivation

Event date:
Report date:
Reporting criterion:	10 CFR 50.73(a)(2)(1) 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability 10 CFR 50.73(a)(2) 10 CFR 50.73(a)(2)(viii)(A) 10 CFR 50.73(a)(2)(ii)(B), Unanalyzed Condition 10 CFR 50.73(a)(2)(viii)(B) 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(x) 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 10 CFR 50.73(b)(3)(v)
4582006002R00 - NRC Website

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En tergy Entergy Operations, Inc.

River Bend Station 5485 U. S. Highway 61 N St. Francisville, LA 70775 Fax 225 635 5068 March 27, 2006 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

Subject:

Licensee Event Report 50-458 / 06-002-00 River Bend Station - Unit 1 Docket No. 50-458 License No. NPF-47 File Nos.

G9.5, G9.25.1.3 RBG-46551 RBF1-06-0060 Ladies and Gentlemen:

In accordance with 10CFR50.73, enclosed is the subject Licensee Event Report.

This document contains no commitments.

Sincerely, David N. Lorfing Manager - Licensing DNUdhw Enclosure 5 ca :

Licensee Event Report 50-458 / 06-002-00 March 27, 2006 RBG-46551 RBF1-06-0060 Page 2 of 2 cc:

U. S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011 NRC Sr. Resident Inspector P. O. Box 1050 St. Francisville, LA 70775 INPO Records Center E-Mail Mr. Jim Calloway Public Utility Commission of Texas 1701 N. Congress Ave.

Austin, TX 78711-3326 Mr. Jeff Meyers Louisiana Department of Environmental Quality Office of Environmental Compliance P.O. Box 4312 Baton Rouge, LA 70821-4312

NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION APPROVED BY OMB: NO. 3150-0104 EXPIRES: 06/30/2007 (6-204)

, the NRC may digits/characters for each block) not conduct or ponsor, and a person Is not required to respond to, the

__Information__

___collci n

. PAGE River Bend Station - Unit I 05000 458 1 of 5

4. TITLE Loss of Safety Function of High Pressure Core Spray Due to Manual Deactivation

5. EVENT DATE

6. LER NUMBER

7. REPORT DATE

8. OTHER FACILITIES INVOLVED S IFACILITY NAME DOCKET NUMBER MONTH DAY YEAR YEAR SEQUENTIAL REOV MONTH DAY YEAR 05000 FACILITY NAME DOCKET NUMBER 01 24 2006 2006 - 002 -

00 03 27 2006 05000

9. OPERATING MODE

11. THIS REPORTISSUBMITTED PURSUANTTOTHE REQUIREMENTS OF 10 CFR§: (Checkalthatapply) o 20.2201(b) 3 20.2203(a)(3)(i) 0 50.73(a)(2)(1)(C) 0 50.73(a)(2)(vii) 1 0

20.2201(d) 0 20.2203(a)(3)(ii) 0 50.73(a)(2)(Ii)(A) 0 50.73(a)(2)(viii)(A) 0 20.2203(a)(1) 0 20.2203(a)(4) 0 50.73(a)(2)(ii)(B) 0 50.73(a)(2)(viii)(B) 0 20.2203(a)(2)(1) 0 50.36(c)(1)({)(A) 0 50.73(a)(2)(Iii) 0 50.73(a)(2)(Ix)(A)

10. POWER LEVEL 0

20.2203(a)(2)(ii) 0 50.36(c)(1)(I)(A) 0 50.73(a)(2)(iv)(A) 0 50.73(a)(2)(x) 0 20.2203(a)(2)(lii) 0 50.36(c)(2) 0 50.73(a)(2)(v)(A) 0 73.71(a)(4) 0 20.2203(a)(2)(Iv) 0 50.46(a)(3)(ii) 0 50.73(a)(2)(v)(B) 0 73.71 (a)(5) 100 0 20.2203(a)(2)(v) 0 50.73(a)(2)(i)(A) 0 50.73(a)(2)(v)(C) 0 OTHER 0 20.2203(a)(2)(vi) 0 50.73(a)(2)(i)(B) 0 50.73(a)(2)(v)(D)

Specify In Abstract below or In NRC Form 3B6A

12. LICENSEE CONTACT FOR THIS LER FACILfLY NAME TELEPHONE NUMBER (hIlude Aroa Code)

David N. Lorfing, Manager - Licensing I 225-381-4157

13. COMPLETE ONE UNE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT

CAUSE

SYSTEM COMPONENT MANU-REPORTABLE

CAUSE

SYSTEM COMPONENT MANU-REPORTABLE FACTURER TO EPIX FACTURER TO EPIX NA

14. SUPPLEMENTAL REPORT EXPECTED

15. EXPECTED MONTH DAY YEAR SUBMISSION o YES (If'yes, complete 15. EXPECTED SUBMISSION DATE) 0 NO DATE ABSTRACT (Limit to 1400 spaces, ie., approximately 15 single-spaced typewritten lines)

On January 24, 2006, at 7:32 p.m. CST, the high pressure core spray (HPCS) system was Inadvertently initiated during surveillance testing. The plant was operating at 100 percent power at the time. The HPCS Injection valve was open for approximately 40 seconds before the operators manually closed the valve. The Division 3 diesel generator (DG) also automatically started In response to the actuation signal. The DG did not automatically connect to the Division 3 switchgear since there was not a low voltage condition on that bus. The manual closure of the injection Isolation valve caused the system to be Incapable of responding to an automatic actuation signal. The manual override of the injection Isolation valve was reset approximately 97 minutes after the event, restoring the system to Its standby condition. This event was caused by lack of procedural guidance concerning test leads needed for the surveillance. The affected procedures were subsequently revised and successfully completed.

This event Is being reported In accordance with 10CFR5073(a)(2)(iv) as an Invalid actuation of the HPCS system, and with 10CFR50.73(b)(3)(v)(d) as a condition that caused the loss of function of the HPCS system. This event is also reportable pursuant to River Bend Station Technical Requirements Manual Section 5.6.9.2., "ECCS Systems Actuations."

NRC ORM 66(-200)

PRNTE ON ECYCED APE NRC FORM 366 (6Z2004)

PRINTED ON RECYCLED PAPERU.S. NUCLEAR REGULATORY COMMISSION (1-201)

LICENSEE EVENT REPORT (LER)

FAILURE CONTINUATION

1. FACILITY NAME

2. DOCKET

6. LER NUMBER

3. PAGE YEAR SEQUENTIAL IREVISION I

NUMBER NUMBER River Bend Station - Unit 1 05000-458 2006 002 00 2

OF 5

REPORTED CONDITION On January 24, 2006, at 7:32 p.m. CST, the high pressure core spray (HPCS) (BG) system was inadvertently initiated during surveillance testing. The plant was operating at 100 percent power at the time. The HPCS injection valve (**INV**) was open for approximately 40 seconds before the operators promptly implemented the appropriate response procedures and manually closed the valve. The operators shut down the HPCS pump approximately three minutes after the initiation. The Division 3 diesel generator (DG) (**DG**) also automatically started in response to the actuation signal. The DG did not automatically connect to the Division 3 switchgear since there was not a low voltage condition on that bus. This event is being reported in accordance with 10CFR5073(a)(2)(iv) as an invalid actuation of the HPCS system, and with 10CFR50.73(b)(3)(v)(d) as a condition that caused the loss of function of the HPCS system. HPCS Is a single-train safety system. The manual closure of the injection isolation valve caused the system to be incapable of responding to an automatic actuation signal. The manual override of the injection isolation valve was reset approximately 97 minutes after the event, restoring the system to its standby condition.

This event is also reportable pursuant to River Bend Station Technical Requirements Manual Section 5.6.9.2 regarding ECCS system actuations. This event was the thirteenth HPCS injection since initial plant startup in October 1985.

INVESTIGATION At the time of the event, Instrumentation & Controls (I&C) technicians were performing a scheduled surveillance test procedure (STP) to calibrate instruments in the HPCS initiation circuitry. Other than the conditions required for this test, the HPCS system was in its normal standby configuration. This was one of four companion STPs scheduled during the nights of January 23rd and 24th that test redundant channels in the system. These tests Involve checking for trip circuit continuity through a multi-pin test jack on the panel containing the trip units. One pair of STPs checks the B-to-C pins (performed on January 23rd) and the other STPs set checks the A-to-B pins (scheduled for January 24th).

River Bend had previously evaluated a similar event that occurred at another plant in 2003. Prior industry operating experience had identified that this type of test (checking inside the multi-pin jack itself) Is risky due to the possibility of making contact with the wrong connections. River Bend evaluated different types of test fixtures and determined that since just two pins are needed for each pair of tests, an enhanced "break-out" test lead exposing only two pins at a time would involve less risk of error. One break-out lead was built for testing the B-to-C pins, and another was built for the A-to-B pins.U.S. NUCLEAR REGULATORY COMMISSION (1-2001)

LICENSEE EVENT REPORT (LER)

FAILURE CONTINUATION

1. FACILITY NAME

2. DOCKET

6. LER NUMBER

3. PAGE YER SEQUENTIAL REVISION YEAR NUMBER NUMBER River Bend Station - Unit 1 05000-458 2006 002 00 3

OF 5

STPs were successfully performed the night prior to the event using the B-to-C break-out lead. The test being conducted at the time of the event required the use of the A-to-B break-out lead. The B-to-C break-out lead was used instead. The STPs do not specifically Identify the break-out lead to be used, but identify the need to check continuity across certain pins. The break-out leads are labeled as to which pins they make available for continuity check. Other than the information on the label Itself, the leads look alike (i.e., color and length). Starting the test with the incorrect break-out lead installed trips half the logic circuitry required for a system actuation. A trip of the rest of the circuit, as done during the test, completed the actuation signal leading to the actuation of the Division 3 DG and HPCS system. The operators responded using the appropriate response procedures, and closed the HPCS injection valve. The remaining tests were postponed pending an Investigation.

Immediate corrective actions were taken to positively identify the two break-out leads, and to revise the STPs. Briefings on the event were conducted for the I&C technicians.

The remaining tests were successfully performed the following night.

Plant equipment and systems responded appropriately to the initiation signal. The HPCS injection caused reactor vessel water level to increase from 36 to 45 inches of water. Reactor feedwater controls responded to compensate for the Injection flow.

Reactor power, as indicated on the average power range monitors, did not change during the Injection. The Division 3 DG was loaded as required by procedure. The DG was returned to its standby condition at 11:56 p.m.

CAUSAL ANALYSIS The STP being conducted at the time of the event required the technicians to take continuity measurements between pins A and B on the multi-pin test jack. The procedure did not specify which break-out lead to use. The technicians did not recognize the uniqueness of one break-out lead and the other.

In addition, the RBS procedure writers' guide did not clearly address human factors defenses.

Although the operating experience from the 2003 event was used and corrective actions Implemented to prevent the event from occurring at RBS, it still occurred. A review of the corrective actions Initiated In response to the 2003 event found that the decision was made that no procedure revisions were needed. Critical thinking of Maintenance personnel did not lead to consideration of what would happen if the tools (i.e., break-out leads) were improperly used.U.S. NUCLEAR REGULATORY COMMISSION (1.2X1)

LICENSEE EVENT REPORT (LER)

FAILURE CONTINUATION

1. FACILITY NAME

2. DOCKET

6. LER NUMBER

3. PAGE YEAR SEQUENTIAL REVISION I

NUMBER lNUMBER River Bend Station - Unit 1 05000-458 2006 002 00 4

OF 5

CORRECTIVE ACTIONS TO PREVENT RECURRENCE The break-out leads involved in this event have been color coded and re-labeled for positive identification. The affected procedures have been revised to provide specific identification of the required break-out leads.

A review of the STPs was conducted after this event, and it found that thirteen other procedures involve the use of similar test leads. This review determined that none of these STPs specifically identify the test leads, nor do they contain steps to verify the correct test lead is being used. Actions have been initiated to correct this procedure deficiency, and will be tracked In the RBS corrective action program. As previously described, a human performance stand-down and briefing on this event were conducted for the I&C maintenance staff.

Actions have been initiated to revise the RBS procedure writers' guide, as well as to enhance critical thinking and human factor defense management. These actions will be tracked In the RBS corrective action program.

PREVIOUS OCCURRENCE EVALUATION A similar HPCS initiation at another boiling water reactor in September 2003 had been evaluated at RBS as operating experience. As described above, that review did not result in the procedure revisions that could have prevented this event.

SAFETY ANALYSIS

The RBS Updated Safety Analysis Report addresses an inadvertent initiation of HPCS.

Analyzed reactor pressure and temperature variations are relatively small and no significant consequences are expected. The minimum critical power ratio remains above the safety limit and, therefore, fuel thermal margins are maintained.

Plant equipment responded appropriately to this event. There was no observable change in reactor power, as measured by the average power range monitors.

Calculated thermal power, as measured by the plant process computer heat balance, decreased because feedwater mass flow rate is the primary measured variable of the plant heat balance calculation. The HPCS injection was replacing part of this flow, but It is not Included in the heat balance calculation.

The main feedwater control system reduced feedwater flow rates in response to the HPCS injection, minimizing the reactor water level transient.U.S. NUCLEAR REGULATORY COMMISSION (1-2001)

LICENSEE EVENT REPORT (LER)

FAILURE CONTINUATION

1. FACILITY NAME

2. DOCKET

6. LER NUMBER

3. PAGE I

YEAR SEQUENTAL REVSION Y

I NUMBER INUMBER River Bend Station - Unit 1 05000-458 2006 002 00 5

OF 5

While the manual "close" signal was present on the HPCS injection valve, that valve would not automatically re-open in response to any subsequent system Initiation. In that circumstance, the HPCS pump would have automatically started and operated on the minimum flow path. Had the safety function of the system been necessary, the injection valve could have been manually re-opened. During the 97 minutes that the Injection valve was overridden closed, there was no condition requiring an actual operation of the system.

This event was of minimal significance to the health and safety of the public.

(NOTE: Energy Industry Component Identification codes are annotated as (**XX**).)

NRC FORKM 366B (1-2W1 )