05000247/LER-2017-002

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LER-2017-002, Auxiliary Feedwater Flow Indication Inoperable for Longer Than the Allowed Technical Specification Completion Time Due to Failure of Complete Restoration Following Calibration
Indian Point 2
Event date: 2-6-2017
Report date: 08-22-2017
Reporting criterion: 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications
LER closed by
IR 05000247/2017003 (27 October 2017)
2472017002R00 - NRC Website
LER 17-002-00 for Indian Point, Unit 2 Regarding Auxiliary Feedwater Flow Indication Inoperable for Longer Than the Allowed Technical Specification Completion Time Due to Failure of Complete Restoration Following Calibration
ML17240A167
Person / Time
Site: Indian Point Entergy icon.png
Issue date: 08/22/2017
From: Vitale A J
Entergy Nuclear Northeast
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-17-106
Download: ML17240A167 (6)


comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Indian Point 2 05000-247 2017 - 00 Note: The Energy Industry Identification System Codes are identified within the brackets { }.

DESCRIPTION OF EVENT

On March 6, 2017, Instrumentation and Control (I&C) maintenance had a scheduled activity to calibrate the 22 Steam Generator (SG) {SB, SG} Auxilary Feedwater (AFW) flow indicator (FI-1201) {FI}. The tag-out was applied by Operations at

0748 hours
0.00866 days
0.208 hours
0.00124 weeks
2.84614e-4 months

on the two flow transmitter root stop valves. l&C personnel began to calibrate FI-1201 at approximately

1000 hours
0.0116 days
0.278 hours
0.00165 weeks
3.805e-4 months

. The calibration procedure requires isolation of the high and low isolation valves and opening of the equalizing valve to allow venting of any pressure going to the transmitter. The calibration was performed and all as- found readings were within acceptance range. The test equipment was removed. The transmitter restoration was completed with the exception of filling and venting the transmitter FI-1201 and placing back in service Due to the root valves being tagged out, the source of water was isolated preventing proper filling and venting of the transmitter. The I&C supervisor discussed the restoration of the transmitter with the Shift Manager (SM) and it was agreed that Operations would complete restoration of the transmitter when the tag-out was removed. The I&C supervisor noted this and marked NA for the steps to return the transmitter back in service. This is a common practice when performing transmitter calibrations as a part of larger work windows because the tag-out must first be removed for a source of water to be available for restoration. Conditions that have to be met when using N/A are specified by the Procedure as follows:

- "IF the method by which processes are performed may affect safety related equipment or technical specifications, as determined by a supervisor, then changes shall not be made without a licensed senior reactor operator approval.

This procedural requirement could be considered met since the Operations shift manager had agreed to restore the transmitter to service.

However, the Procedure further states the following:

- "Two knowledgeable individuals shall agree with the steps or sections to be marked "N/A", of which one shall be a supervisor or above, or the approving Senior Reactor Operator (SRO), if applicable based on supervisor determination. Both individuals who agreed shall initial and date the steps marked N/A before the document is considered complete.

Based on the requirement of the Procedure, the l&C supervisor should have obtained the shift mangaer's initials prior to considering the document was complete. However, the l&C supervisor did not obtain the shift manager's initials prior to considering the document was complete, as required by Procedure. Consequently, Operations did not restore the transmitter to service, resulting in FI-1201 remaining inoperable for greater than the Technical Specification 3.3.3 allowed completion time of 30 days.

Depending on the total scope of work in the work window, the transmitter restoration is either performed by l&C per the Procedure or by Operations as directed in the restoration section of the tag-out sheet. The Operations shift manager intended to have the transmitter filled and vented correctly when the tag-out was removed from the transmitter, but this was not effectively communicated to the facility shift supervisor (FSS) or the next shift. Without any communication to the SRO (FSS), who was approving tag-out removal, that Operations would be responsible for restoring the transmitter, the expectation would have been that the transmitter would be restored by the I&C Procedure steps that fill and vent the transmitter. This was a case of inadequate communication between the shift manager who made the agreement and the rest of the shift.

- 002 comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Indian Point 2 05000-247 2017 - 00 The status of plant equipment should be known at all times by Operations. The control of plant equipment status is governed by Entergy "Component Deviation" and/or "Component Verification and System Status Control" Procedures.

For situations where no procedural guidance (e.g., operating procedures, protective or caution tagging, or an open work order which restores the system/component), and the component is required to be placed in a position different from its normal alignment, the realignment must be performed in accordance with approved plant specific processes.

Component status should be tracked in the applicable approved plant specific process prior to manipulation unless time does not permit logging the component prior to operation. Logging should be completed at the earliest opportunity. Had the shift manager logged the deviation in either the Narrative log, turnover log and/or Check Off Lists (COL's), this issue would have been known and corrected.

The barriers in place for control of plant equipment include procedures, work orders and/or tagging. When none of these are applicable, then the component status should be tracked using the appropriate plant specific process or the 1201 remained inoperable for greater than 30 days. This exceeded the Technical Specification Limiting Condition for Operation (LCO) 3.3.3 Condition A allowed Completion Time of 30 days. It should be noted that in spite of inoperability of FI-1201, since FI-1201 is indication only, there was no actual loss or degradation of water flow to the steam generators at any time and thus had no impact on SG heat removal capability.

CAUSE OF EVENT

Direct cause was due to the root valves being tagged out, isolating the source of water, thus preventing proper filling and venting of the transmitter.

The following two (2) causal factors (CFs) were identified:

  • CF-1- Poor verbal and written communications between the shift manager and field support supervisor. The status of the transmitter and the need to be filled and vented following tag-out removal was not logged or turned over to the on- coming operations shift in accordance with procedures (Committed Action Not Carried Out - Inadequate Tracking )
  • CF-2- The procedure steps were marked NA by the MC supervisor without having the second initial which was required by the procedure (Misjudgment - Lack of Validation or Verification)

CORRECTIVE ACTIONS

The following corrective actions will be performed under the Entergy Corrective Action Program to address the causes of this event.

  • Operations to ensure component deviations are logged as per relevant procedures. This requirement will be reviewed with all Operations shifts and used as operating experience (OE) for Operations training.
  • l&C superintendent to direct supervisors not to NA the steps in the procedure and to verify completion of the steps
  • prior to closing the work order. (The intent of this Corrective Action is to ensure l&C supervisors do not NA steps to return instrumentation to service without verifying that the instrumentation has been returned to service.)
  • Review with all Maintenance First Line Supervisors (MFLS) the procedure steps requirements of marking NA for safety related equipment and the requirement for two initials, one being the approving SRO and a supervisor or above.

- 002 comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Indian Point 2 05000-247 2017 - 00

EVENT ANALYSIS

The event is reportable under 10 CFR 50.73(a)(2)(i)(B).The licensee shall report any event or condition which was prohibited by the Technical Specifications.

On March 6, 2017, FI-1201 was removed from service for scheduled calibration. Technical Specification LCO 3.3.3, Post-Accident Monitoring (PAM) Instrumentation, and Table 3.3.3-1 require four channels of the AFW flow function (Function 19) to be operable in Modes 1, 2, and 3. With one channel of the AFW flow function inoperable, Condition A of the LCO requires the inoperable channel to be restored to operable status within 30 days. As previously described in this Licensee Event Report (LER) poor verbal and written communications between the shift manager and FSS resulted in FI-1201 not being restored in a timely manner. This condition was discovered on June 26, 2017, following an Indian Point Unit 2 (IP2) manual reactor trip (IP2 LER 2017-001-00), when it was observed that the 22 SG AFW flow indication (FI-1201) remained at zero gallons per minute (gpm) when the associated motor-driven AFW pump {P} flow control valve {FCV} was verified to be 70 percent open. On June 27, 2017, FI-1201 was restored, declared operable, and Technical Specification LCO 3.3.3 Condition A was exited. The time duration that FI-1201 was out of service and inoperable exceeded the allowed 30-day Completion Time, and constitutes a condition prohibited by the Indian Point Unit 2 Technical Specifications.

PAST SIMILAR EVENTS

A review was performed of the past three years of Licensee Event Reports (LERs) for events related to failures to restore the Auxiliary Feed Water (AFW) Flow Instrumentation to service within the required Technical Specification completion time due to the causal factors identified. No LERs were identified.

SAFETY SIGNIFICANCE

There was a loss of PAM AFW flow indication due to this event, but since this is an indication only, there was no actual loss or degradation of water flow to the steam generators at any time and thus had no impact on SG heat removal capability. Hence, this event had no effect on the health and safety of the public.

In the IP2 design, two motor-driven AFW pumps provide redundant, automatically actuated trains for loss of feedwater events and design basis accident mitigation. There are two AFW flow indicators per AFW pump, with one flow indicator connected to a feedwater line for each of the four SGs. Hence, there are two automatically actuated motor-driven AFW pumps feeding four SGs, with two AFW flow indicators per AFW pump. Since the purpose of the AFW flow indicators is to monitor SG decay heat removal capability, the flow indicators are redundant on a per heat sink basis. Accordingly, the loss of one channel of AFW flow indication, as reported in this LER, did not result in a loss of SG heat removal monitoring capability. Moreover, alternate redundant Type A, Category I PAM instrumentation is provided by the SG water level (narrow range) indication for monitoring SG heat removal capability. The SG water level indication function remained available during the period that the FI-1201 AFW flow indication channel was inoperable.

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