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On November 26, 2017. at 1225 Eastern Standard Time (EST), the Watts Bar Nuclear Plant (WBN) Unit 2 experienced an unplanned Emergency Core Cooling System (ECCS) discharge to the Unit 2 Reactor Coolant System (RCS) while de-pressurized. in Mode 5. with the Pressurizer vented to the Pressurizer Relief Tank.

ECCS injection via the Boron Injection flow path occurred during planned Safety Injection system Engineered Safety Features Actuation System (ESFAS) testing. The Boron Injection flow path should have been isolated and should not have resulted in any injection flow to the Unit 2 RCS. The condition was promptly corrected by operator actions based on observed plant conditions.

The cause of this event is that an Operator improperly used a Caution Order to determine the configuration of the breaker for the Boron Injection Tank outlet valve. Correct Component Verification was not utilized as required. and the current position of the breaker in the field was not validated to support testing.

Corrective actions for this event include revising procedures to ensure the breakers associated with the boron injection flow path will be tagged open during ESFAS testing and that lessons learned related to this event are communicated to operating crews. An evaluation on the use of Caution Orders for off normal equipment positions will be performed .

NRC FORM 330604-2O'

On November 9, 2017 at approximately 2300, Salem Unit 1 was operating in MODE 3 when operators found steam leaking into the mechanical penetration area outside containment. Operators entered S1.0P-AB.STM-0001, Excessive Steam Flow, and dispatched operators to locate and isolate the leak.

Operators determined the steam was from the 14 steam generator through normally closed valves 14GB47 and 14GB48 steam generator blowdown (WI) line nitrogen supply valves. The steam leak was isolated at 2314 when operators closed normally open manual valve 14GB3.

This report is made per 10CFR50.73(a)(2)(i)(B), Any operation or condition which was prohibited by the plants Technical Specifications.

This was caused by human performance. Procedures will be revised to assure containment integrity exceptions are tracked and open valves are closed while sampling during the sparging process.

NRC FORM 3116 (04-20171

On November 3, 2017, at 2022 hours, with reactor power at 100 percent, Indian Point Unit 3 experienced an automatic reactor trip on a turbine trip, which was in response to a main generator trip. The main generator trip was initiated by actuation of the Generator Protection System due to a main generator loss of field.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System (AFWS) automatically started as expected on steam generator low level to provide feedwater flow to the steam generators. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the loss of main generator field was a failed Thyristor Firing Module drawer which affected proper operation of the redundant Thyristor Firing Module drawer. The root cause was determined to be that the Automatic Voltage Regulator (AVR) Firing Module power supplies have a latent design vulnerability where shared common output nodes are not isolated after a failure. A plant modification is proposed that will eliminate the condition by electrically isolating the AVR Firing Module power supplies upon failure.

This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on November 3, 2017 under 10 CFR 50.72(b)(2)(iv)(B) and 50.72(b)(3)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System when the reactor is critical and a valid actuation of the AFWS.

On 10/23/2017, during a walkdown of containment at the start of the Unit 3 refueling outage, a leak was identified in a socket weld for a 1-inch diameter instrument line. The line is connected to discharge piping for the 'B' recirculation pump and is part of the reactor coolant system pressure boundary. Because the leak was misting, the leakage rate could not be quantified. However, the reactor coolant system unidentified leakage prior to plant shutdown was 0.18 gpm. RCS pressure boundary leakage while in Mode 1 is a violation of Technical Specification 3.4.4 and is a reportable condition.

The cause of the event was a lack of fusion defect in the weld when it was done in the late 1980's. Normal vibration of the line since it was installed resulted in the crack initiating at the weld defect and propagating to the surface. The section of pipe and associated fitting were replaced, along with welds in similar sections of piping. There were no actual safety consequences as a result of this event.

On October 29, 2017, Unit 1 entered MODE 3 from MODE 4 without satisfying all of Technical Specification 3.7.5, Auxiliary Feedwater (AFW) Limiting Conditions for Operation (LCO) as required by LCO Applicability 3.0.4 for the Turbine Driven Auxiliary Feedwater (TDAFW) pump system.

LCO Applicability 3.0.4 does not permit entry into a MODE of applicability when an LCO is not met, unless the associated actions to be entered permit continued operation in the MODE for an unlimited time or after performance of an acceptable risk assessment and the appropriate risk management actions have been established. After entering MODE 3, it was discovered that components were not operable, contrary to LCO 3.0.4.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B), for an operation or condition prohibited by Technical Specifications.

On October 16, 2017, with Unit 2 shutdown for a refueling outage, investigation into a boric acid indication identified a through wall leak at the socket weld that joins a 3/4 inch line to Loop A Reactor Coolant System (RCS)(AB) shutdown communication line valve 2RC-8-37 )(VTV). The leak was isolated by closed valves that would have limited primary coolant leakage to within the capacity of the charging system when the reactor coolant system was pressurized. The quantity of dry boric acid at the location was small (estimated at 1/2 teaspoon in volume). This failure constituted a welding or material defect in the primary coolant system that was not found acceptable under ASME Section Xl and an event or condition prohibited by Technical Specifications.

The cause of the leakage was determined to be stress corrosion cracking. Valve 2RC-8-37 was replaced. In addition, Prairie Island Nuclear Generating Plant intends to perform phased array ultrasonic inspections of socket welds on similar Class 1 piping containing stagnant water during future refueling outages.

On August 23. 2017. Watts Bar Nuclear Plant (WBN) identified that procedures 1-E-1 and 2-E-1, Loss of Reactor or Secondary Coolant, contained steps to manually open 1-FCV-67-458 in the event of a Train A or B power failure.

Opening 1-FCV-67-458 would result in the crosstie of Essential Raw Cooling Water (ERCW) Headers 2A and 1B, which would lead to providing flow to equipment not operating due to the loss of a train of power. On October 6. 2017.

it was determined that for certain time periods, if a design basis accident had occurred on Unit 2 with a loss of offsite power concurrent with a train failure and with 1-FCV-67-458 opened, inadequate ERCW flow would have been available to remove decay heat after transfer to cold leg recirculation. This condition only affected operability of ERCW Train A. This is reportable as a condition prohibited by Technical Specification 3.7.8.

The issue associated with this incorrect procedural step to cross-tie the ERCW trains in 1-E-1 and 2-E-1 was addressed as part of actions to resolve an ERCW design and procedure issue documented in Licensee Event Report (LER) 390-2017-009. This report, while related, identifies an issue that was not addressed in the prior LER. The cause was determined to be the incorrect application of a cross tie requirement associated with 10 CFR 50 Appendix R. Corrective action will be to include engineering in the review of procedures affected by complex design changes.

NRC FORM 355 ;:;4-217' APPROVED BY OMB: NO. 3150-0104 EXPIRES: 03/31/2020 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 NEOB-10202. (3150-0104), Office of Management and Budget. Washington, DC 20503. If a means 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.

On June 8, 2017 at 1527 hours, the reactor automatically scrammed due to a loss of Main Turbine- Electro-Hydraulic Control (EHC) logic power causing a high neutron flux, Reactor Protection System (RPS) trip. The safety systems operated as expected. Secondary Containment differential pressure lowered to 0" WG due to a trip of the normal operation of the Reactor Building Ventilation system. The differential pressure was restored by the initiation of Standby Gas Treatment System.

The scram was caused directly by a DC+ (direct current, positive) test lead (Maxi Grabber) that inadvertently contacted with the grounding screw, causing a short and momentary loss of EHC logic power.

Immediate action was taken to validate that there was no damage to the +30 VDC (volts DC) EHC logic.

The root cause for this event is an insufficient focus on the High Risk Activity of adjusting the EHC power supply, and inadequate risk mitigating actions for that activity.

The condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the RPS, including reactor scram. Although no safety system functional failure occurred, this event is also reportable pursuant to 10CFR 50.73(a)(2)(v)(C) as a condition that could have prevented fulfillment of a safety function. There were no actual, or potential consequences to the health and safety of the public as a result of this event.

I

On July 17, 2017, at 1606 CDT, Waterford 3 experienced an automatic reactor scram due to a loss of forced circulation, which was the result of a loss of off-site power to the safety and non-safety electrical busses. Prior to the scram, plant operators manually tripped the main turbine and generator due to overheating of the isophase bus duct due to the failure of a shunt assembly connection in the duct to Main Transformer 'B'. The automatic electrical bus transfer did not occur due to relay failures in the fast dead bus transfer system. Both 'A' and 'B' Emergency Diesel Generators started and loaded as designed to re-energize the 'A' and 'B' safety busses. The loss of off-site power caused a loss of both Main Feedwater pumps, resulting in an automatic actuation of the Emergency Feedwater system.

The Root Cause of this event was the design change procedure used for modifications to the fast dead bus transfer circuitry did not include guidance to detect the susceptibility of the relays to DC coil inductive kick. The faulty relays in the fast bus transfer circuit were replaced prior to plant startup.

An Unusual Event was declared at 1617 CDT due to loss of off-site power to safety buses for >15 minutes.

All required safety-related equipment responded as expected during this event.

On June 26, 2017, Operations commenced a downpower from 100 percent to 93 percent reactor power to support performance of the Main Turbine Stop and Control Valve Test. With reactor power at 94 percent, the 22 Main Boiler Feed Pump Turbine (MBFPT) speed control trouble alarm annunciated coincident with pump speed swings of 800 revolutions per minute (rpm). The operators ceased the downpower and placed the 22 Main Boiler Feedwater Pump (MBFP) in Manual speed control to control the rpm swings. This was unsuccessful, and the rpm swings continued. The 22 MBFPT low pressure (LP) governor valves were observed to be cycling from full-closed to full-open. The decision was made to take local pneumatic control of the 22 MBFP to stabilize pump speed. Two minutes after establishing local pneumatic control, the LP governor valves went to full closed. With the rapid reduction in 22 MBFP speed, the pump was no longer delivering feedwater flow to the SGs. An automatic main turbine runback signal should have been generated on a low speed signal; however, there was no turbine runback actuation. In response, the operators commenced a manual runback to reduce main turbine load, but the decreasing SG levels reached 15 percent, and at 1531 hours a manual reactor trip was initiated.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the reactor trip was that the shoulder screws used on the 22 MBFPT LP governor valve servomotor linkage had backed out and detached. This caused the LP governor valves to fail closed, shutting off the turbine steam supply. This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on June 26, 2017 under 10 CFR 50.72(b)(2)(iv)(B), 50.72(b)(2)(xi), and 50.72(b)(3)(iv)(A).

On June 11, 2017, while at 100 percent reactor power, Operations placed Chemical and Volume Control System (CVCS) Demineralizer Diversion Valve CH-TCV-149 in DIVERT to allow the 32 Mixed Bed Demineralizer to be removed from service and align the 31 Mixed Bed Demineralizer for service. Within about two minutes after returning CH-TCV-149 to AUTO, which placed the 31 Mixed Bed Demineralizer in service, Letdown Backpressure Control Valve CH-PCV-135 demand had gone to 0 percent (full open demand) while letdown backpressure had increased, reaching 302 psig.

Operations was alerted to a leak that had developed on 32 Mixed Bed Demineralizer Inlet Isolation Valve CH-352. In an effort to isolate the leak, CH-TCV-149 was placed in DIVERT. Due to the elevated pressure at CH-TCV-149 with CH-PCV- 135 fully open, placing CH-TCV-149 in DIVERT coupled with the elevated line pressure created a pressure transient in the letdown line upstream of the CVCS Reactor Coolant Filter. Reactor Coolant Filter Inlet Isolation Valve CH-305 experienced this pressure transient, which resulted in the valve developing a significant leak at the body to bonnet joint. Abnormal Operating Procedure (AOP) 3-AOP-LEAK-1 was entered, and normal letdown was manually isolated to stop the CH-305 leak. Excess letdown was placed in service to balance reactor coolant inventory at a Pressurizer water level of 61 percent.

This exceeded the 54.3 percent limit of Technical Specification 3.4.9 Condition A, and Operations declared the Pressurizer inoperable. The inoperability of the Pressurizer is reportable as a safety system functional failure under 10 CFR 50.73(a)(2)(v). The direct cause of this event was elevated system pressure due to loading of the Reactor Coolant Filter from materials when the 31 Mixed Bed Demineralizer pathway was aligned. The elevated operating pressure in the CVCS letdown stream challenged the integrity of diaphragm valves CH-352 and CH-305, requiring the isolation of normal letdown.

On June 6, 2017, at 1357 (EDT) with the reactor at 100% core thermal power and steady state conditions, plant personnel were performing Ultrasonic testing (UT) examination on Core Spray A high point piping in the A Residual Heat Removal Quad to ensure this piping was water solid, when they identified that the top of this horizontal pipe had an air void internally. A high point vent line with valves is located in the area of the UT exam.

It was found that the top 2 inches of the 10 inch core spray pump discharge line had accumulated an air void within the known inverted loop in Core Spray Loop-A discharge line. The system had been drained for maintenance during the Refueling Outage.

Pilgrim Nuclear Power Station is reporting this event pursuant to 10 CFR 50.73(a)(2)(i)(B), as a condition prohibited by Technical Specifications. Although upon discovery the proper Limiting Condition for Operation Action Statement was entered and the void was filled immediately to correct the issue, it is believed that this condition existed before the time of discovery for a period of time longer than that allowed by Technical Specifications.

This event posed no threat to public health and safety.

On July 31, 2017, FPL determined that the proceduralized manual actions to mitigate postulated electrical single failures in the St. Lucie Unit 1 hot leg injection (HLI) flow path were inadequate. Manual actions previously developed based on failure modes and effect analysis (FMEA) failed to identify the need to override open permissive interlocks in the HLI flowpath. The procedures were revised to account for the oversight, and a detailed FMEA was performed and enhancement opportunities were identified to be evaluated under the site corrective action program.

The safety significance for the additional jumper scope was bounded by previous evaluations. Therefore, this event had no significant impact on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means 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.

Description of the Event

On July 31, 2017, with St. Lucie Unit 1 in Mode 1 at 100 percent reactor power, it was determined that the proceduralized manual actions to mitigate postulated electrical single failures in the St. Lucie Unit 1 hot leg injection (HLI) flow path were inadequate. The existing procedures lacked actions to address the installation of jumpers required to defeat the reactor coolant system (RCS) pressure interlocks for valves V3481 and V3652 (EIIS:BP:V) when aligning the plant for HLI. The procedures were immediately revised to include the instructions necessary to restore power to the affected valves. The required 8-hour NRC ENS notification was completed at 1832 hours.

A more detailed failure modes and effects analysis (FMEA) was completed to assure no other issues; although enhancements to improve margin were identified, there were no further issues identified that would preclude HLI flow for all strategies.

Cause of the Event

The reason the HLI initiation procedures were inadequate was that the previous FMEA to open V3481 and V3652 to provide hot leg injection was incomplete. This cause is a legacy human performance error associated with the level of detail and rigor in the evaluation and documentation of the capability to provide hot leg injection. A contributing factor was that the control circuits for valves V3481 and V3652 are not typical; the interlocks that prevent opening the valves are not powered from the MCC for the valve actuator.

Analysis of the Event

Reporting Criteria This condition is reportable pursuant to 10 CFR 50.73(a)(2)(ii)(B) as any event or condition that resulted in the nuclear power plant being in an unanalyzed condition that potentially degraded plant safety.

Background

Long-term core cooling and boron precipitation was identified during the initial licensing of St. Lucie Unit 1. Because the St. Lucie Unit 1 original design did not provide dedicated hot leg injection paths, St. Lucie Unit 1 was licensed to develop HLI procedures that utilized the existing low pressure safety injection (LPSI) and/or high pressure safety injection (HPSI) flow paths for hot leg injection.

There are five potential paths for implementing HLI. The preferred HLI flow path is to direct the discharge of one LPSI pump (EIIS:BP:P) through the 2-inch shutdown cooling (SDC) warm-up line to the opposite pump's suction line, and "backwards" through the suction line into the hot leg. The cold leg injection is via the normal HPSI pump (EIIS:BQ:P) operation. This flow path requires the opening of two motor operated valves (MOVs) in series to be successful; each valve is powered from a different electric bus.

Valves V3481 and V3652 are the cross-train powered SDC return isolation valves for the respective 1A and 1B SDC cooling loops. Loss of power scenarios were Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means 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.

mitigated by the contingency use and installation of staged electrical jumpers to provide power for these valves from the opposite train motor control center (MCC).

However, the previous FMEA failed to identify that these valves' control circuits contain open permissive interlocks to prevent subjecting the lower pressure portion of the SDC system to the higher reactor coolant system (RCS) pressure.

The FMEA performed for the 2011 LER failed to identify the need to defeat this interlock by installation of low voltage jumpers in the control room.

This condition is not applicable to St. Lucie Unit 2 as it has a dedicated HLI flow path as part of its original design.

Analysis of Safety Significance The mechanism for potential boron precipitation is described in Unit 1 UFSAR Chapter 6 Appendix C. For a hot leg break, the injection flow passes from the cold legs, through the core, into the hot legs, and out the break. For a hot leg break, core heat removal is via forced flow of the injection water. In contrast, for a cold leg break, after the reflooding is completed, the hydraulic balance will cause most of the injection flow to spill out of the break - the only flow into the core will be that required to make-up for the boil-off in the core that removes the core decay heat. The boron problem arises only during a cold leg break; as borated injection flow enters the core, and only pure water (as steam) leaves the core, the boron concentration in the core region will continue to increase. Once the boron concentration exceeds the solubility limit the boron will precipitate and potentially challenge long-term core cooling capability. The solution to the potential problem is to achieve subcooled flow through the core:

when boron in equals boron out, the concentration will not be increasing.

St. Lucie uses simultaneous hot and cold leg injection as the method to achieve forced flow through the core for long-term post-LOCA cooling. With simultaneous hot and cold leg injection, the recirculated sump fluid is injected into the hot legs as well as the cold legs. Regardless of break location, sufficient flow is delivered to provide heat removal and flush the core to prevent the concentration of boron from reaching the solubility limit.

The operators are procedurally required to initiate HLI within four to six hours post-accident.

If the loss of an electrical bus required the use of the proceduralized jumpers, the emergency response organization (ERO) problem solving teams in the technical support center (TSC) and emergency operation facility (EOF) would most likely diagnose and mitigate the open permissive interlock and initiate HLI within the required timeframe. The 2011 LER evaluated the safety significance for the use of knowledge-based instead of rule-based jumper installation, and the additional low voltage control circuit jumper scope identified in this LER does not materially affect the conclusions of the previous LERs. Based on these considerations, this event had no significant impact on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means 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.

Corrective Actions

The corrective actions listed have been entered into the site corrective action program (CAP). Any changes to the actions below will be processed in accordance with the CAP.

1. The additional jumper scope was added to the proceduralized manual actions for bypassing the de-energized interlocks for SDC suction valves.

2. A more detailed FMEA was completed and additional enhancements to improve margin were identified. These enhancements are being tracked in CAP.

Identified Failed Components None

Additional Information

St. Lucie Unit 1 LERs 2011-003-00 (ADAMs accession number ML12023A003) and 2011- 003-01 (ADAMs accession number ML12081A282) reported the use of unproceduralized manual actions to accomplish HLI.

On May 10, 2017, at 0907 Eastern Daylight Time (EDT), Watts Bar Nuclear Plant (WBN) Unit 1 operations personnel discovered the 1B-B Safety Injection pump discharge isolation valve (1-ISV-63-527) closed. Technical Specification (TS) 3.5.2, ECCS - Operating, Condition A was immediately entered for one or more trains of the Emergency Core Cooling System (ECCS) inoperable. TS 3.5.2 Condition A was exited at 0913 EDT when 1-ISV-63-527 was opened.

Investigation determined that the 1 B-B SI pump discharge isolation valve had been closed prior to Unit 1 entering Mode 3 on April 26, 2017, representing a condition prohibited by TS. During this time period, the 1A-A SI pump was inoperable for 21 minutes, representing a condition that could have prevented fulfillment of a safety function.

The cause of the mispositioned valve was the result of an individual failing to follow procedure use and adherence requirements during the performance of Emergency Diesel Generator (EDG) Blackout testing. The safety injection pump discharge valve was closed to support the test but was not reopened following the testing. Corrective actions for this event include personal accountability actions, revision of the EDG blackout procedures to ensure the SI pump discharge valves are reopened, and additional station focus on procedure use, particularly use of Not Applicable (N/A) in performing procedures.

On February 23, 2017, at 19:22 hours, with Unit 1 and Unit 2 operating at approximately 100 percent power, operators commenced a Unit 2 shutdown upon discovery of pressure boundary leakage on Unit 2 Safety Injection (NI) pipe upstream of the connection to "D" Reactor Coolant System (NC) Cold Leg. During a containment walk down inspection in Mode 3 on the next day, a pinhole pressure boundary leak was observed in the body of 2NC-30, Pressurizer Spray Bypass Valve.

The cause of the NI pipe leak is thermal fatigue damage caused by NC cross-loop flows. The cause of the 2NC-30 valve leak is a casting flaw attributed to a combination of defects during the manufacturing process that resulted in a through wall pinhole leak in the valve body. The NI pipe with the flaw and the valve with the pinhole leak could have structurally performed their design functions. Therefore, the health and safety of the public were not affected by these events.

Valve 2NC-30, the NI pipe, and leaking B-Loop NI check valves were replaced. Thermal cycling monitoring and mitigation devices were installed on Unit 2 and will be installed on Unit 1 during the next refueling outage.

On March 8, 2017, at 1627 CST, it was identified that Low Pressure Safety Injection (LPSI) train ‘B' was inoperable due to SI-135B, Reactor Coolant Loop 1 Shutdown Cooling Warmup Valve, being found open, which is not the required position. At the time of discovery, LPSI train ‘A' was inoperable for maintenance and the station was in compliance with Technical Specification (TS) 3.5.2 action ‘a' which requires that an inoperable LPSI train be restored within 7 days. The shift operating crew entered TS 3.5.2 action ‘c' due to both trains of the Emergency Core Cooling System being inoperable. Action ‘c' requires that with both LPSI trains inoperable, at least one train must be restored within one hour.

SI-135B was subsequently closed and tested to verify operability. TS 3.5.2 action 'c' was exited at 1705. The station remained in compliance with TS 3.5.2 action ‘a'.

It was determined that the SI-135B valve was opened inadvertently. It was planned to perform work on SI-135A, Reactor Coolant Loop 2 Shutdown Cooling Warmup Valve. The workers incorrectly began work on SI-135B and manually opened the valve. This was caused by personnel not performing proper component verification to validate that they were on the correct component, contrary to station procedures. Corrective actions are being performed to improve station work practices related to component verification.