Text

FOIA-2023-000198 - Released Set
	ML24059A161
Person / Time
Issue date:	02/21/2024
From:	; NRC/OCIO
To:	; - No Known Affiliation
References
	FOIA-2023-000198
	Download: ML24059A161 (39)
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JULY 2023 INSPECTOR NEWSLETTER 1

Inspector Newsletter July 2023 Providing useful information to our inspectors, by our inspectors!

Contents Betas, Bremsstrahlung, and Best Practices............................................... 1 What's Wrong with This Picture #1?.... 2 CP RI Office IT Infrastructure Update

Work Stoppage.................................... 3 Checking Up on Things In the Fleld... 4 What's Wrong With This Picture #2?.... 5 OpE Regarding RCP and Recirculation Pump Seals................... 6 SONGS GTCC Cannister Lid Weld -

Field Inspection Enables Identification of Weld Inadequacy.... 7 OpE Related to Inadequate Surveillance/Observation of Natural Terrain Credited as a VBS................... 8 The Inspector Newsletter Goes International!........................................ 9 Deep-Seated Fires............................. 11 Letters to the Editor......................... 13 Overcoming Resistance and Adding Value................................................... 13 Not Your Cousin Eddie's Testing

............................................................. 15 The OpE Fishing Hole......................... 16 Remember When............................... 16 Answer to "What's wrong #2"........... 19 Catch of the day................................ 19 Eagle Eyes Award.............................. 20 NRR Staff Supported the FANR, UAE First FP Inspection at Barak,ah NPP 21 FOR INTERHA:L 1:JSE o*uv Betas, Bremsstrahlung, and Best Practices During a decommissioning inspection at Three Mile Island (TMI) Unit 2 to review the site's radiation protection program focusing on dosimetry, Harry Anagnostopoulos, Senior Health Physicist, RI/DRSS/DIRHP, identified a technical flaw in the licensee's approach. Specifically, while reviewing a white paper on the beta attenuation of personal protective equipment (PPE) materials at increasing dose rates, he identified that the testing method was not a true beta test. The test involved the use of a beta source with various laye*rs of shielding to test the beta attenuation of the PPE at different radiation levels, but the use of shielding itself was problematic. When betas traverse through materials, they create bremsstrahlung or "braking radiation" usually In the x-ray range of energy when betas slow down in the vicinity of electric fields (see diagram below), so the resultant dose fields were a mix of beta/x-rays or solely x rays Instead of all betas as intended. This invalidated the results of the PPE testing reported by the white paper, especially at low dose rates where none of the betas would have made it through the shielding, so the attenuation of the materials was inappropriately being tested by x rays. Harry identified this when reviewing the associated test result tables and questioned the zero attenuation at low dose rates versus the higher attenuation factors recorded at the higher dose rates. When Harry pointed out this technical flaw in the testing technique to the licensee, they wrote a corrective action condition report (CR) and assigned a corrective action to re perform the testing using a beta source-using distance instead of shielding to get the various dose rates necessary.

(continued next page)

[KT: A beta particle is a fast-moving electron emitted by radioactive decay of substances.

X-rays are produced by high-energy electrons bombarding a target, especially targets that have a high proton number (Z). When bombarding electrons penetrate into the target, some electrons travel close to the nucleus due to the attraction of its positive charge and are subsequently influenced by its electric field. The course of these electrons would be deflected, and a portion or all of their kinetic energy would be lost. The principle of the conservation of energy states that in producing the X-ray photon, the electron has lost some of its kinetic energy. The

'lost' energy is emitted as X-ray photons, specifically bremsstrahlung radiation

{bremsstrahlung is German for 'braking radiation').]

JULY 2023 INSPECTOR NEWSLETTER 2

feR INTERNAL US! ONLY Appropriate analysis and use of PPIE in beta fields is incredibly important at TMI-2 due to the strong beta component of the dose fields in parts of the plant, mainly from Sr-9O/Y-90 due to the spread of these fission products during the accident. Y-90 has a 2.28 MeV maximum beta energy. A general rule of thumb is that a beta can travel 8 - 12 feet in air per MeV-demonstrating the importance of appropriate PPE to provide protection, particularly for the eyes.

Identification of this issue demonstrates the use of critical thinking in review of documentation, including "don't accept things at face value" and the use of fundamental health physics concepts. Great catch, Harry!

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Half <:2G science is p1Attin9 Porth the right questi0.ns.

- FrtlntiJ {j~\\t!);,i What Questions Have Yo,u Asked Today?

What's Wrong with This Picture #1?

JULY 2023 INSPECTOR NEWSLETTER 3

FOP INTERNAi 115E ONI Y Comanche Peak Resident Inspector Office IT Infrastructure Update - Work Stoppage

Region IV Stai*- Neil Day In March 2023, through cooperation between RIV and HQ IT departments, IT infrastructure was to be updated to add modern technology in the NRC resident office. This update promised additional speeds and security that were warranted and desired by all resident inspectors.

Due to the specifics of the location of Comanche Peak, hardware was to be installed within the NRC IT infrastructure in the resident office IT closet. This hardware was procured by an NRC contractor and sent to a licensee IT individual for installation. In March 2023, the licensee dropped in to deliver and install the IT hardware equipment. As expected, Mr. Neil Day, welcomed the individual into the office for further dialogue to understand the planned changes. Through Mr. Day's courteous yet relentless questioning, he determined that the licensee wanted to update NRC phone equipment to voice over internet protocol and use the licensee IT framework to accomplish this upgrade.

Mr. Day is a long-time resident inspector but, like many of us, has limited understanding of IT technology. He immediately recollected Ray Powell's (qualification program mentor) conversations/training to ensure that the resident office requires independent infrastructure from the licensee to accomplish our mission objectively. Neil understood that he lacked the appropriate skills to oversee a licensee IT individual making these changes, so he stopped the licensee from installing the upgrade and discussed the proposed changes with the regional experts.

After consultation with RIV's IT individuals, it was determined that the licensee's change would have compromised NRC's independent IT infrastructure. Additionally, it could have challenged the Resident Office Security Plan. Mr.

Day's questioning attitude highlighted the importance of independence, service and mission commitment and asking for help when unsure.

II Safety isn't expensive, it's priceless "

Content Search of the Current NRC Inspection Manual We have two new tools available to search the inspection manual. The ADAMS folks have worked diligently to provide a robust, web-based search engine. However, it searches all versions of the document.

The second tool allows content search of the current, public Inspection Manual. That tool is available in SharePoint; the link is also stored on the ROP Digital City site (right side under Inspection Manual (IM)).

Looking for a prior version of an Inspection Manual document? See the penultimate link in the same section of Digital City; it provides a clickable link to the document issuing package.

Finally, if you want to quickly see the change history for a manual chapter or inspection procedure, use RRPS report number IPAS 8-9. This report provides the contents of the "Description of Change" column in the document history table.

JULY 2023 INSPECTOR NEWSLETTER 4

Checking Up on Things in the Field (Getting a Leg Up on the Licensee) by Chris Highley, Susquehanna Senior Resident Inspector F9R DITEAPllib USE 9Nb¥ The emergency service water (ESW) system is a safety-related system designed to provide a reliable source of cooling water to support operation of the emergency core cooling system and reactor core isolation coolant room coolers, emergency diesel generators (EDGs), the Unit 2 direct expansion units, and control structure chillers as needed during normal plant operation, transient plant operation, and under plant accident conditions. The ESW system consists of four pumps that are divided into two loops, each of which is designed to supply 100 percent of the ESW cooling requirements to both Susquehanna units and the common EDGs simultaneously. The four pumps are located in the ESW pumphouse at the edge of the spray pond. The ESW system is designed to take water from the spray pond, discharge flow through the various heat exchangers and cooling loads in both units, and return the flow to a common residual heat removal SW/ESW return header to the spray pond for dissipation of heat to the atmosphere. Each ESW pump has a discharge check valve, which opens to permit required pump flow and closes when the pump is off to prevent reverse flow if the second pump in the loop is operating.

On January 6, 2023, the 'A' ESW pump discharge check valve failed to close after securing the pump and operators initiated a corrective action condition report (CR). Operators started the 'C' ESW pump to provide reverse flow to shut the

'A' ESW pump discharge check valve, but it still did not close. Operations then used both the 'C' ESW pump reverse flow and an in-field equipment operator (EO) manually closing on the valve arm to get the valve closed. Operators declared the 'A' ESW pump inoperable and entered the associated TS LCO. On January 7, maintenance repacked the valve, but the valve still would not close on its own and required an EO pressing on the arm to close the valve. Operations determined that the 'A' ESW pump discharge check valve was operable (crediting backflow from the redundant pump) and exited the TS LCO. Additionally, based on a CAP review, the licensee had identified that the 'A' ESW pump discharge check valve had failed to close on securing the pump on three instances during 2022. On February 3, the inspectors observed the securing of the 'A' ESW pump and observed that the discharge check valve did not close. The EO in the field pushed the valve closed with their foot using the external valve arm. The EO commented that the valve was getting harder to close. On February 10, the 'A' and 'C' ESW pumps were in operation to support EDG testing. When the 'A' ESW pump was secured, the backflow from the 'C' ESW pump was insufficient to close the 'A' ESW pump discharge check valve as required, operators initiated another CR to document the condition, and declared the 'A' ESW loop inoperable.

The inspectors note that ASME OM Code 2004 ISTC-5221 (a)(l) for check valve obturator movement states, in part, that "check valves that have safety function in both directions shall be exercised by initiating flow and observing that the obturator has traveled to either the full open position or position required to perform its intended function, and verify that on cessation or reversal of flow, that the obturator has traveled to the seat." Additionally, ISTC-5224, Corrective Action, states, in part, "if check valve fails to exhibit the required change of obturator position, it shall be declared inoperable. A retest showing the acceptable performance shall be run following any required corrective action before the valve is returned to service." The inspectors reviewed the ESW operating procedure and an associated supporting calculation. The operating procedure allowed the operator to manually close the ESW pump check valves with reasonable force without declaring the loop inoperable. However, the licensee determined that the calculation that supported this approach had an error, such that the force applied by the reverse flow was a factor of four lower than the calculated value. The licensee also captured this shortcoming in a CR. Based on direct observations i11 the field and an independent calculation of the torque applied by the EO, the inspectors engaged in further discussions with station personnel concerning the calculation and the forces applied by the manual operation which resulted in the licensee determining that the manual closing of the ESW pump discharge check valves did not meet the inservice testing criterion. This was documented in another corrective action CR. The licensee's corrective actions included replacing the 'A' ESW pump discharge check valve with a rebuilt one and revising the ESW system operating procedure to remove the allowance for manual closure of the check valve (requiring use of reverse flow from the other pump to close the valve). [See NRC Inspection Report 05000387 &

388/2023001 for more details.]

Inspector Best Practices noted above:

Independently verify when possible. There is no substitute for being there and seeing firsthand. What did the licensee overlook or fail to consider?

JULY 2023 INSPECTOR NEWSLETTER 5

Ensure that you share your field observations with Operations and/or Engineering, as appropriate, in a timely manner. Do not analyze the condition for them or lower your standards.

Go the extra mile. This may involve reviewing the system history (including maintenance, STs, mods, & operating experience), the licensee's CAP database, design basis calculations, vendor manuals, ASME Code requirements, operating procedures & logs, and the UFSAR.

Make sure that your field observations align with the design basis and good engineering judgment. Is the compensatory measure appropriate, properly implemented, and adequate to ensure continued operability/functionality of the degraded SSC?

Learn to listen; listen to learn. Operator engagement is essential.

Routinely talk to reactor operators and equipment operators to get their thoughts on plant performance, resolution to previous issues, and operator burdens and challenges.

Follow up periodically to ensure corrective actions adequately addressed the problem. In addition, for identified deficiencies that are not promptly corrected, follow up periodically until the issues are resolved to ensure conditions do not degrade further.

Maintain a questioning attitude. Albert Einstein defined insanity as doing the same thing over and over again and expecting different results.

POPt: INTERN.tel USE 8NLY Can you identify this pamphlet?

Click the picture for the story.

What's Wrong With This Picture #2?

What's wrong with the above picture? After pondering the picture for a few minutes, flip back to page 19 for the answer.

JULY 2023 INSPECTOR NEWSLETTER 6

f6R lN"fER,tl,b Uii ONI Y Operating Experience Regarding Reactor Coolant Pump and Recirculation Pump Seals By Lauren Bryson, General Engineer NRAN Between 2021 and 2023, at least 14 plants have had unplanned shutdowns or extended outages to address issues with reactor coolant pump (RCP) or recirculation pump seals. Prior to that only 19 plants in the previous 10 years had similar issues. While RCPs and recirculation pumps are not considered safety-related equipment, they form a part of the reactor coolant system (RCS) pressure boundary.

There are several designs of pump seal packages typically consisting of multiple stages. The various stages limit the leakage between rotating and stationary pump elements, as well as between pump elements having only slight motion relative to one another. These seals require continuous cooling both during pump operation and at hot shutdown conditions with the pump stopped. Failure of the seal package, whether from lack of cooling, excessive wear, or other means, can result in the equivalent of a 2-inch small break loss of coolant accident. Seal failures in these pumps can have serious consequences for plant operation and safety.

Several factors can contribute to seal failures including:

improper maintenance

parts quality

temperature and pressure transients

operation during low pressure conditions

friction between seals

high vibration

contamination

loss of AC power to plant For example, in 2022, Robinson Unit 2 (INPO Failure ID 514127, proprietary 1 had to enter a forced outa e to re lace an RCP seal. b 4 (b)( 4)

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Among 14 events reviewed from 2021-2023, in each case the licensee recognized the seal degradation and took actions to ensure plant operation remained within analyzed limits.

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__,~o view these INPO summaries. Contdct your Regional OpE Cohldcl if you would like to view the full lNPO failure item.

JULY 2023 INSPECTOR NEWSLETTER 7

POiit: 11\\ITl!IUU~L USI! ONLY SONGS GTCC Cannister Lid Weld - Field Inspection Enables Identification of Weld Inadequacy

Regi,on IV Sta Ii-Lee Brookhart and Jack Freeman In March 2023, Lee Brookhart and Jack Freeman performed an onsite inspection at San Onofre Nuclear Generating Station. Their plan was to be onsite during the processing of the first canister to store Greater-Than-Class-C (GTCC) waste generated from the Units 2 and 3 containments. The GTCC waste are pieces of the reactor vessel internals cut up and placed into transportation/storage canisters. When the inspectors arrived onsite, they were informed that the first lid had been welded onto the canister and vacuum drying was in progress. Without hesitation, and following all high radiation area radiation protection protocols, they entered containment and the locked high radiation area at the top of the canister to directly observe the welding work that was completed prior to their arrival. The inspectors observed the post-weld condition of the canister inner lid and promptly noted two areas that looked to be a little shallow. Pulling the string, they identified that the procedure acceptance criteria was inadequate, in that It only specified the weld needed to be "near-flush". The procedure should have annotated specific acceptance criteria to ensure the weld met design thickness. The licensee measured the weld depth following their questions and identified that it was, in fact, less than what the design required. The licensee took action to build up the weld, correct the procedure to have appropriate acceptance criteria, and verify weld thickness via NOE methods.

This was the inner lid of a TN/NUHOMS transportation canister which does not function as the confinement barrier.

The outer lid satisfies that function. However, If the inspectors had not been there to catch this, the licensee would have proceeded to weld the outer lid in place and move the canister into the independent spent fuel storage module in a condition that did not satisfy all design requirements. It was fortunate (intentional by DIOR branch planning) that the inspectors caught this on the first of ten canisters such that the licensee could correct this canister and the procedure/process to ensure the remaining nine were done correctly.

This finding resulted in a Severity Level IV NCV and demonstrates the importance of risk-informing inspections for key evolutions, in-field observation to verify critical steps were performed adequately, and using a questioning attitude when something doesn't look quite right. The performance demonstrated by Lee and Jack highlight why Independence is one of the NRC's Principles of Good Regulation.

Don't lose touch with safety -

wear your safety gloves when climbing.

Controuersy in the last issue of the Inspector Newsletter?

Click the picture to find out why.

or just keep reading

JULY 2023 INSPECTOR NEWSLETTER 8

POlt INTERNAL USE 6NL¥ Operating Experience Related to Inadequate Surveillance/Observation of Natural Terrain Credited as a Vehicle Barrier System

Background

During the week of August 22, 2022, a licensee that credited natural terrain as a component of its vehicle barrier system (VBS) was found to be in a noncompliant condition. Over time, the licensee's natural terrain had changed in a manner that no longer allowed the terrain feature to meet its intended function as a VBS. Specifically, trees within the owner-controlled area that were credited as the VBS had degraded over time to a point that would allow vehicle passage without the awareness of site security. This condition was partially attributable to inadequate observation or surveillance by the licensee at a frequency sufficient to detect the degradation. Additional information related to these events are contained in Official Use Only-Security Related Information inspection reports.

Discussion Licensees are required to identify and analyze site-specific conditions to determine the specific use, type, function, and placement of physical barriers needed to satisfy the physical protection program design requirements of 10 CFR 73.55(b). Furthermore, 10 CFR 73.55(e)(l0)(i)(C) requires licensees to provide periodic surveillance and observation of vehicle barriers and barrier systems adequate to detect indications of tampering and degradation or to otherwise ensure that each vehicle barrier and barrier system is able to satisfy the intended function. This includes natural terrain features that the licensee relies upon to meet the requirements associated with its VBS. Those natural terrain features may be susceptible to degradation over time. Specifically, natural terrain features can erode due to severe weather, and trees can fall and decay over time. When natural terrain features degrade, it could lead to noncompliance on the part of the licensee if the features no longer meet the requirements for a physical barrier.

Licensees must continue to assess natural terrain features to ensure they do not degrade or erode over time and do not represent exploitable conditions.

This information is being widely communicated to NRC inspectors due to the large number of licensees throughout the industry that take credit for natural terrain as a means of satisfying the VBS requirement in 10 CFR 73.55. Natural terrain features that are credited a!:i VBS may be !:iUSceptible tu change!:i that could degrade their ability tu satisfy the intended function. Additionally, depending on the type of natural terrain, the surveillance and observation frequency should be revisited by the licensee to ensure compliance with the security plan commitments. Licensees that seek more specific guidance should also refer to both NUREG/CR-4250 "Vehicle Barriers: Emphasis on Natural Features,"

and NU REG/CR-6190-V2-Rl, "Protection Against Malevolent use of Vehicles at Nuclear Power Plants: Vehicle Barrier System Selection Guidance."

Please report any observations concerning the degradation of natural terrain credited as VBS to the Office of Nuclear Security and Incident Response (NSIR) for tracking and trending purposes. The NSIR points of contact are Daryl Johnson and Maury Brooks.

Inspector Best Practices are noted below:

Independently verify when possible. There is no substitute for being there and seeing firsthand. What did the licensee overlook or fail to consider? In this case, the licensee failed to consider how natural barriers (e.g.,

bodies of water, terrain, or vegetation) could be subject to change over time.

A picture is worth a thousand words. Trying to describe how and where a fallen tree in the woods negatively impacted a licensee's physical protection program could prove to be a challenge. Thanks to the forward thinking by the inspector(s), they were able to capture multiple images that clearly illustrated the fallen tree and its proximity to the PA barrier.

Good inspection practices include the age-old question, "have you considered the extent-of-rnndition?" This extent-of-condition review may uncover a programmatic issue and/or increase the risk significance depending upon the condition of other similar SSCs. In this situation, the licensee was able to identify other trees that were somewhat questionable, for which additional compensatory measures were installed.

Maintain a questioning attitude. The inspector, after reviewing the licensee surveillance and observation procedure for the accredited VBS, questioned the licensee's ability to make the determination that the barrier was capable performing as planned. Specifically, the inspector noted that in some areas, there were no checks, surveillance, or patrols to verify the integrity of the accredited !barrier. This prompted the inspector(s) to dig deeper, which ultimately lead to the discovery of the fallen tree.

Trust but verify. Never be overly reliant on information such as pictures, diagrams or drawings provided by the licensee. This information represents a particular moment in time and is subject to change. As inspectors, nothing compares to putting "boots on the ground." This statement is especially true when Natural Terrain, which is subject to degradation, is being credited as a regulatory required security barrier.

Phone a friend. Remember that the headquarters staff, regional staff, and other inspectors, are excellent resources to tap into to help put your issue in perspective.

JULY 2023 INSPECTOR NEWSLETTER Physical Security Inspector, Mike Ordoyne, evaluates a potential vehicle approach pathway created by a downed tree.

9 EQB JNifBNAI IISE QNI Y The Inspector Newsletter Goes International!

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By Tom Hipschman I recently attended an international regulator counterparts meeting, and a staff member from the Japan Nuclear Regulatory Agency (NRA) shared with me that they have translated our inspector newsletter into Japanese for the use of their inspectors. I think the following letter from the Director-General for Nuclear Regulation needs no explanation regarding the value your inspection efforts provide to them.

JULY 2023 INSPECTOR NEWSLETTER

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NRA,Japan

.....,., Nuclear Rogulation Autl'ICN11Y April 28, 2023 Mr. Thomas Hlpscl'1man Chief. Reactor lnspecnon Branch 10 Dl\\iis1on or lnspectM>n and Regional Support Office of Nuclear Reactor Regulahon U S. Nuclear Regulatory Commission Sub]ee1 Inspector Newsletters Dear Mr. Hlpschman I would like to show our appreciation to US-NRC for a series ol generous support Including Inspector Newsletters on behalf of NRA.

As you know NRA decided to take NRC's ROP for a model in reforming our inspection program. Since then, US-NRC have been giving us a series of gcnorous support Bocauso concepts that are applied In ROP such 11s pertormance-based and rlsk-1nfo1Tned are quite new to us, we are facing a lot of challenges. 1 believe that your supports are essential ror us to overcome these challenges EsoeClally, changing mindset or tnsoee1ors who used to locus on document review In their lnspe<:oon undor our prevM>us r.ompllance-ba scdlprocess-onented lnspection program Is a big challenge We tnvrted several inspectlon masters from US*NRC as coaches. Our inspectors learned a lot or sklll and tips from then on srte Furthennore your ln!pector newsletters made our Inspectors known Power or Obs1;1rvetlon'. II was so Impressed at the first glance. I directed my sta" to translate 11 to share,n our inspector community. We use rt a lot as a tool of cl11nfy1119 m3nagement's expectation to 111spectors Occasionally we ere discussing -stones from these newsletters el our IO$peclor counterpart meeting I would be glad, If you oould let editor know that these newsletters ere helpful beyond his/her imagination.

Sincerely yours

~

Yesushl MORISITA Director-General for Nuclear Regulation Nuclear RegutoUon AuthontY JAPAN

Enclosure:

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JULY 2023 INSPECTOR NEWSLETTER 11 F9R INTERNAL USE 8NL¥ Additionally, the Japan NRA has translated our NRC Inspector Field Observation Best Practices (NUREG/BR-0326) for use by their inspectors.

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Thank you to our newsletter team, contiributors, and inspectors who make each edition of the newsletter the best ever. We also express much appreciation to our Japanese colleagues for their kind comments. Our ongoing cooperation with them continues to improve our inspection and oversight practices. (Click here to go back to the pamphlet on page 6.)

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Deep-Seated Fires Naeem Iqbal, Fire Protection Engineer/ Reliability and Risk Analyst, NRR/ DRA/ APLB Introduction Two types of fires can occur in Class A (ordinary) combustibles materials (e.g., wood, cloth, paper, rubber, and many plastics including cable insulation). In the first type, commonly known as flaming combustion, the source of combustion is volatile gases resulting from heating or decomposition of the fuel surface. In the second type, commonly called smoldering or glowing, combustion oxidation occurs at the surface of, or within, the mass of fuel.

These two types of fires frequently occur concurrently, although one type of burning may precede the other. For example, a wood fire may start as flaming combustion and become smoldering as burning progresses. Conversely, spontaneous ignition in a pile of oily rags may begin as a smoldering fire and break into flames at some later time.

Smoldering combustion cannot be immediately extinguished like flaming combustion. This type of combustion is characterized by a slow rate of heat loss from the reaction zone. Thus, the fuel remains hot enough to react with oxygen, even though the rate of reaction, which is controlled by diffusion processes, is extremely slow. Smoldering fires can continue to burn for many weeks, for example in bales of cotton and jute and within heaps of sawdust or mulch. A smoldering fire ceases to burn only when all of the available oxygen or fuel has been consumed, or when the temperature of the fuel surface becomes too low to react. These fires are usually extinguished by reducing the fuel

JULY 2023 INSPECTOR NEWSLETTER 12 FOi\\ 11'1Tl!RNlcL USE 9NL:Y temperature, either directly by applying a heat absorbing medium (such as water), or indirectly by blanketing the fuel with an inert gas. In the latter case, the inert gas slows the rate of reaction to the point at which heat generated by oxidation is less than the heat lost to the surroundings. This causes the temperature to fall below the level necessary for spontaneous ignition following removal of the inert gas atmosphere.

Smoldering fires are divided into two classes, in which the fire is either deep-seated or not. Basically, "deep-seated" implies the presence of sub-surface smoldering combustion that may continue for some time after surface flaming is suppressed. Deep-seated fires may become established beneath the surface of fibrous or particulate material. This condition may result from flaming combustion at the surface or from the ignition within the mass of fuel. Smoldering combustion then progresses slowly through the mass. Whether a fire will become deep-seated depends, in part, on the length of time it has been burning before the extinguishing agent is applied. This time is usually called the "pre-burn" time.

As described above, a deep-seated fire is embedded in the material being consumed by combustion. To extinguish deep-seated fires, an individual must investigate the interior of the material once the surface fire has been extinguished to determine whether interior smoldering has also been extinguished by a gaseous agent. It should be noted, however, that the concentration of the extinguishing agent must be adequate-and must be applied for an adequate duration-to ensure that the smoldering has been effectively suppressed.

Deep-Seated Electrical Cable Fires A deep-seated fire occurs in electrical cables when the burning involves pyrolysing beneath the surface, in addition to a surface phenomenon. This is postulated to occur when the cable fire reaches the stage of a fully developed fire.

Extinguishing a cable surface fire does not guarantee that a deep-seated fire is also eliminated. A deep-seated fire is very difficult to suppress since fire suppressing agent cannot easily get to the seat of the fire, and it is also difficult to detect since combustion is primarily under the cooler surface.

Electrical cable fire tests have been conducted at the Sandia Fire Research Facility, NUREG-2431, "Burn Mode Analysis of Horizontal Cable Tray Fires," February 1982, ADAMS Accession No. ML062260264, in order to evaluate cable tray fire safety criteria. A burn mode concept was developed in order to describe and classify the thermodynamic phenomena which occur in the presence of smoke and to compare the fire growth and recession of different cable types under otherwise, unchanged fire test conditions. The importance of deep-seated fires in cables trays from the standpoint of propagation, detection, and suppression is emphasized. The cable tray fire tests demonstrate that fire recession and deep-seated fires can result from a decreasing smoke layer and that reignition and secondary fire growth is possible by readmission of fresh air.

Operating Experience On February 3, 2001, San Onofre Nuclear Generating Station, Unit 3, was operating at 39-percent power following a refueling outage. While switching offsite power sources for Unit 3, a non-safety-related 4160V circuit breaker faulted and initiated a fire in the secondary switchgear room, a Unit 3 turbine and reactor trip, and transfer of the safety and some non-safety-related electrical loads to Unit 2 sources. The firefighters discharged portable Halon and dry chemical fire extinguishers through the cabinet vents in an attempt to extinguish any active fire within the cabinet. With the exception of some low-voltage circuits, all power was isolated to the 4160V switchgear. The firefighters then determined that the cubicle door could be opened safely. Upon opening the cubicle door, the firefighters observed flames within the cubicle, and discharged additional dry chemical in another attempt to extinguish the flames. The firefighters then closed the cubicle door as a containment measure. The cubicle door was subsequently opened several times, and each time the door was opened, in-rushing air caused the fire to reflash. Firefighters then used dry chemical each time the fire reflashed. The San Onofre Nuclear Generating Station fire department captain spoke directly with the shift manager to advise him that the deep-seated fire could not be extinguished unless water was applied, the shift manager granted permission to use water to extinguish the fire. The fire was ultimately extinguished after firefighters applied water. The deep-seated fire burned for approximately 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months before finally being extinguished. NRC Information Notice 2002-27, "Recent Fires at Commercial Nuclear Power Plants in the United States," September 20, 2002, (ML022630147). San Onofre Nuclear Generating Station NRC Special Team Inspection Report 50-362/01-05, April 20, 2001, (ML011130225).

Deep-Seated Charcoal Fires The use of activated charcoal in nuclear power plants presents a potential for deep-seated fire. Simply, that if it says that it is combustible, that it may be ignited, and that if it does become ignited, it is likely to become a deep-seated fire. It does not predict the frequency of those fires, nor form of ignition. On July 17, 1977, a fire occurred at the Browns Ferry Nuclear Power Plant in Unit 3 off-gas system charcoal adsorber bed. The elevation in adsorber bed temperature caused temperature rises of sufficient magnitude to cause carbon ignition. As a result, the Browns Ferry Nuclear Power Plant in Unit 3 was shut down for a forced outage. The details of the fire event can be found at : LA-9911-C, Vol. II Conference CNS! Report No. 83, pp. 309-316, "Proceedings of the CSNI Specialist Meeting on Interaction of Fire and Explosion with Ventilation Systems in Nuclear Facilities," October 1983.

JULY 2023 INSPECTOR NEWSLETTER 13 FOR 1141 ERIIAC USE ONLt

N1ZC---NRC---NRC-N1ZC---NRC** N!lC-N1lC-N?iC----NRC-MlC** N!lC----NRC---NllC---NllC-IVJIZC**NRC---NRC---NRC-N1lC-N1lC---NRC-NRC-N1ZC---NRC-SCRAM Jam - A reactor achieves criticality (and is said to be critical) when each fission event releases a sufficient number of neutrons to sustain an ongoing series of reactions. Like criticality, the SCRAM acronym challenge appears to have evolved into a self-sustaining reaction and may help to fuel our quarterly newsletters for some time. You may recall that in the January Inspector Newsletter, the response to the acronym challenge stated that "the origin of SCRAM was 'Safety Control Rod Axe Man' - a term supposedly coined by Enrico Fermi when the world's first nuclear reactor was built under the spectator seating at the University of Chicago's Stagg Field but open to debate in the nuclear field." Well, it looks like that debate is still going on. In the April Inspector Newsletter, Kelly Korth named the safety control rod axe man, Norman Hilberry, and provided a copy of an email that he had sent out years ago containing more interesting facts on the first nuclear chain reaction.

In response to Kelly's update in the April newsletter, we were honored to hear from our very own NRC Historian, Tom Wellock, who stated that he had reached a different conclusion on the topic (origins of the SCRAM acronym) based on his research over the years (including talking with Warren Nyer, who was present on that historic occasion). We were copied on a very polite, professional, and informative e-mail exchange between Kelly and Tom on this topic. We pasted below links to Kelly's sources and to two of Tom's NRC blog postings (dated 5/7/11 and 2/18/16). We invite you to review the information (including blog comments), perform your own independent research if desired, and reach your own conclusion. We encourage you to continue to keep us straight, keep us informed, and certainly keep us on your reading list.

[We also included a link below to a YouTube video that Kelly recommended that featured Warren Nyer and his personal account of that momentous day.]

((DIT0JJ lIID The "SCRAM" story came from Argonne National Labs: https://www.ne.anl.gov/About/legacy/piqlet.shtml There is more at Argonne: https://www.ne.anl.gov/About/legacy/

https://public-bloq.nrc-qateway.qov/2016/02/18/refresh-puttinq-the-axe-to-the-scram-myth/

https: //pu bl ic-bloq. n re-gateway. gov/ 2011/05/17 /putting-the-axe-to-the-scram-myth/

https://www.youtube.com/watch ?v=OtKf7R2XncM (Back to the scram button on page 8)

Overcoming Resistance and Adding Value by Scott Rutenkroger, Peach Bottom Senior Resident Inspector Design & licensing basis: Peach Bottom Atomic Power Station (PBAPS) was required by NRC Order EA-13-109 to have a reliable, severe accident capable hardened containment vent system (HCVS). Phase 1 of the order required upgraded the venting capabilities from the containment wetwell to provide a reliable, severe accident capable hardened vent to assist in preventing core damage and, if necessary, to provide venting capability during severe accident conditions. PBAPS modified the existing hardened wetwell vent path that was installed in response to NRC Generic Letter 89-16 to comply with NRC Order EA-13-109. The EA-13-109 compliant HCVS system added a dedicated 125 Vdc battery (see picture below), nitrogen motive gas source, and argon purge system to the existing GL 89-16 wetwell hardened vent system. In addition, new HCVS radiation monitoring and temperature sensors and new control switches were added. The dedicated HCVS 125 Vdc battery supplies power to the actuating solenoid for inner primary containment isolation valves and primary containment outboard barrier valves. This battery also powers the new HCVS instrumentation. During an extended loss of AC power, electric power to operate the vent valves will be provided by the battery with a capacity to supply required loads for at least the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Before the battery is depleted, the FLEX generator will repower the battery charger to supplement the required power and recharge the 125 Vdc battery to support operation of the vent valves and instrumentation. NE! 13-02 states that FLEX equipment that directly performs a FLEX mitigation strategy for the core, containment, or spent fuel pool should be subject to maintenance and testing guidance provided in Institute of

JULY 2023 INSPECTOR NEWSLETTER 14 POR ll~Tl!RIUCL U:51! ONlt Nuclear Power Operations AP 913, "Equipment Reliability Process," to verify proper function. NEI 13-0Z also states that site-specific bases will be developed to define specific testing, including that periodic testing and frequency should be done to verify design requirements, and the basis for the testing should be documented and deviations from vendor recommendations and applicable standards should be justified.

The opportunity: On February 17, 2023, the inspectors observed Constellation personnel performing the annual inspection of the containment emergency battery. The inspectors noted that the inspection measured and recorded the internal resistance of the battery cells. However, the procedure did not provide acceptance criteria for internal resistance and cell voltage, nor did it describe providing the data to engineering personnel for evaluation. The inspectors requested further information from engineering personnel and questioned the lack of acceptance criteria. Engineering determined that the cell resistance check is performed for trending as described in the associated vendor guidance and Institute of Electrical and Electronics Engineers (IEEE) 1188-2005, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve-Regulated Lead-Acid (VRLA) Batteries for Stationary Applications." Engineering checked with the battery vendor and determined that an increase of 50 percent from the initial baseline internal cell resistance when new should prompt further scrutiny of battery function, typically provided via performance testing (i.e., a battery discharge test). The HCVS battery average cell resistance first exceeded 50 percent of baseline when the measurements were taken on January 21, 2020. The average cell internal ohmic resistances were determined to be 86 percent above baseline in the most recent test performed on February 17, 2023.

Additional NRC value-added: The inspectors noted that CC-AA-118, "Diverse and Flexible Coping Strategies (FLEX),

Spent Fuel Pool Instrumentation (SFPI), and HCVS Program Document," Attachment 3 lists required PMs tasks for FLEX, SFPI, and HCVS equipment. The listed PMs for VRLA batteries include a three-month cell inspection and one-year detailed cell inspection, with bases listed as "PCM templates, Vendor Recommendations and Battery SME." The PCM template lists both a quarterly cell inspection and annual detailed cell inspection that include measuring cell internal ohmic values. The annual detailed cell inspection also states to compare to previous values. In addition, the vendor guidance and IEEE 1188-2005 both describe performing such cell inspections, including the taking of cell internal ohmic resistance measurements and trending/comparing these measurements to baseline values, and describe that a significant change from baseline values (SO percent per vendor) warrants a performance test (or cell replacement or other corrective action). Notably, the battery inspection procedures, which are used to perform the PMs required by CC-AA-118, list IEEE 1188-2005 as a governing commitment for performing such inspections. Engineering determined that no trending or comparing of cell internal ohmic resistance measurements had been performed, and no performance test had ever been performed on the HCVS battery, which was installed in 2016. IEEE 1188-2005 states that a performance test of the battery capacity should be made upon installation and that batteries should undergo additional performance tests periodically, Further, when establishing the interval between tests, factors such as design life and operating temperatllre should be considered and it is recommended that the performance test interval should not be greater than 25 percent of the expected service life or two years, whichever is less. A routine performance test was not required by CC-AA-118.

However, given that no routine performance testing was being performed, when the internal cell ohmic resistance measurements changed by more than 50 percent above baseline and Constellation did not perform a reactive performance test (or cell replacement or other corrective action), there was no battery discharge testing to credit for meeting PM requirements.

Corrective Actions: As a result of the inspector's questions, Constellation determined that a performance test was required, as described by the vendor and IEEE 1188-2005, to accurately assess the HCVS battery health due to the change in internal cell resistances. Constellation initiated an issue report based on the inspectors' questions and created actions to revise the annual inspection with acceptance criteria and create and implement a performance test procedure as soon as practical within the work scheduling process. (See NRC Inspection Report 05000277 & 278/2023001 for more details.)

It takes a village: Whil.e digging into the concern, the resident inspectors reached out to regional engineering inspectors (Jon Lilliendahl & Joe Schoppy), the Region I SRAs (Frank Arner & Dave Werkheiser), and the Region I enforcement staff (Cherie Crisden) who provided timely and value-added support. Specifically, Cherie validated the violation was appropriate and provided great suggestions to ensure that the violation was clear (especially given the long write-up required to establish it).

Inspector Best Practices noted above:

Remain aware of plant status. This allows you to risk-inform your samples and harvest samples when plant conditions are nipe. This is especially true for infrequently performed tests and PMs.

There is no substitute for being there in-person and seeing firsthand. This NRC identified finding clearly demonstrates the value of inspectors being onsite and in the field.

The devil is in the details. Sometimes, you've got to dig a little bit deeper to unearth hidden facts, discover additional clues, and/or identify disconnects.

JULY 2023 INSPECTOR NEWSLETTER 15 Maintain a questioning attitude. Make sure that your field observations align with the design basis and good engineering judgment.

Do your homework. This may involve reviewing related regulatory guidance, industry operating experience (including the licensee's response as applicable), and the lioensee's design basis documents.

Is there a requirement or a standard (even a self-imposed one) that the licensee failed to meet?

Do not underestimate the value of a thorough document review.

Sometimes, it's not a matter of "what's there" but "what's not there that should be." In the case above, the procedure did not provide acceptance criteria for internal resistance and cell voltage.

Phone a friend. Remember that the regional staff, other residents, NRR OpE Clearinghouse, and the NRR staff are excellent resources to tap to help put your issue in perspective.

Remember, the "I" in "SRI" stands for "inspector." In the key leadership role of SRI it is important not to allow paperwork, reports, and administrivia to keep you out of the plant, especially considering your experience and capability to transfer knowledge to newer inspectors. Peel off the duct tape from your chair! We need you in the field!

POiit: U~T!llt:NAL U!! ONLY The HCVS battery with its protective plastic cover removed.

Not Your Cousin Eddie's Testing Eddy Current Examination, or Eddy Current Testing (ECT), is widely used as the primary nondestructive evaluation (NDE) method for in-service inspection (IS!) of steam generator (SG) tubes during plant outages. These inspections follow site-specific guidelines that prescribe the equipment, techniques, procedures, and training requirements for data analysis. ECT provides valuable information about discontinuities in SG tubes, including their location, origin (i.e., inner, or outer surface), spatial extent, and relative orientation (i.e., axial, circumferential, or volumetric).

During the review of ECT data for the Braidwood, Unit 2, SGs in the 2023 outage, Region 3 Senior Reactor Inspector Atif Shaikh compared the 2023 ECT data from a specific SG tube location against the data from the previous ECT conducted in 2021. This review was conducted virtually using Microsoh Teams, with participation from licensee subject matter experts and Westinghouse resolution analysts located at the vendor's remote analysis site in Pennsylvania. During the virtual resolution review, our inspector requested the Westinghouse SG resolution experts to analyze the 2023 outage ECT data-focusing on flagged indications and areas of special interest such as Anti Vibration Bar (AVB) wear signals and Tube Support Plate (TSP) signals. Of particular interest was an indication in one of the SGs, which was measured to be 67 percent through-wall in 2023. The inspector requested the licensee and vendor to superimpose the ECT signal from the 2021 examination onto the corresponding location of the SG tube. Interestingly, there was a significant signal detected at the same location in 2021, with a similar amplitude to the 67 percent through-wall indication observed in 2023. However, due to the limitations of the data provided and the specific coil (i.e., Bobbin) used for ECT on the free-span length of SG tubes, it was not possible to determine the through-wall dimension of the similar indication from 2021.

Nevertheless, our inspector questioned the licensee and vendor regarding their decision to not call for further examination of this indication signal in 2021. According to the examination technical specification sheet (ETSS), the licensee and vendor were required to scope this signal for further examination using a specialized probe such as a Mechanical Rotating Pancake Coil or Array Probe. Both the licensee and vendor acknowledg,ed the oversight, recognizing that an inadvertent "no call" was made in 2021, given the signal response at that location. They have initiated a corrective action document to investigate how this incorrect indication call passed through four independent levels of review. As a result, the SG tube was plugged during the 2023 outage.

JULY 2023 I NSPECTOR NEWSLETTER 16 The potential consequence of not identifying this particular indication in 2021 could have resulted in an SG tube with a potentially greater than 40 percent thru-wall flaw to be put back in service without being plugged. That condition could potentially compromise the RCS pressure boundary leakage criteria resulting from a primary to secondary leakage or worse, a potential SG tube rupture event during operation. The next scheduled SG ECT exams for Unit 2 would have been 3 cycles out per TS. However, the licensee had to implement secondary side SG repairs (identified during the last outage visual exams) during this 2023 outage and therefore, SG tube ECT was performed again.

While missed calls on potential indications in SG tubes are rare across the industry, this identification by our NRC inspector emphasizes the rigorous review and attention to detail demonstrated during these relatively complex examinations. It underscores the importance of thorough NRC inspections, continuous improvement, specialized technical knowledge, inspection techniques, and the critical role that inspectors play in ensuring the integrity and safety of nuclear plant operations.

The OpE Fishing Hole OpE Hub- (Check it out!)

The NRR Operating Experience (OpE) Branch will use this space to provide periodic updates on topics such as:

Data Access and Data Analytics tools for inspectors and other staff Recent and in-process OpE products (COM Ms, Smart Samples, generic communications, etc.)

INPO Event Trending Dashboard on the OpE HUB The information In INPO Event Trending Is a summarized version of the Information in INPOs operating experience database (Industry Reporting and Information Systems - IRIS). The INPO Event Trending Dashboard on the OpE HUB is a data visualization tool that quickly summarizes industry equipment failure data using interactive charts. The purpose of this tool is to provide users a quick and easy way to view overall trends and patterns of system failures throughout the nuclear industry, as well as generate reports from the INPO IRIS database. If inspectors want to view the entire IRIS entry, contact a member of IOEB and we will provide it.

Inspectors should be sensitive to the Memorandum of Agreement with INPO and to the fact that this information is proprietary. The dashboard can be used to inform inspection planning and samples but should not be used to take regulatory action.

Access to the INPO Event Trending can be found [3,.... **

(b)(4)

Recent OpE Documents OpE COMM - FLEX Generator Catastrophic Failures at Perry and Susquehanna (ML23116A210)

OpE COMM - R.adiation Monitoring Issues Impacting Licensee Emergency Plans (ML23143A126)

Contact and Feedback Please reach out to a member of the branch with any questions or feedback.

OpE Branch Points of Contact Region I Paul Laflamme INPO Robert Beaton Reqion II Robert Beaton Part 21 Paul LaFlamme Region Ill Adam Lee Generic Communications Brian Benney / Phyllis Clark Reqion IV Julie Winslow Dashboards Jason Carneal / Rebecca Siqmon Branch Chief Lisa Re!'.iner 50.72 / 50.73 Julie Winslow I Paul LaFlamme

JULY 2023 I NSPECTOR NEWSLETTER 17 F8R IN'fERPfitrL USE 8NLY Hey, Who Turned Out the Lights?

August 14, 2003, didn't seem like a day for the worst blackout in North American history. The weather in Ohio's Cleveland-Akron metropolitan area was a pleasant 87 degrees with almost dead-calm winds. It was warm enough that many residents ran their air conditioners, but the day's peak electric load of 12,165 MW wasn't close to record breaking.

The Cleveland grid's control area, managed by FirstEnergy Corporation's power distribution staff, was prepared for 800 contingencies of lost power generation or transmission lines. Until mid-afternoon, the system remained within the North American Electric Reliability Council's (NERC) operating standards.

There were complications for the operators. More than most, Cleveland's control area was heavily dependent on just a few local power plants, especially Eastlake (a six-unit, coal-fired facility), the Davis-Besse Nuclear Power Station, and the Perry Nuclear Power Station. Suffering through its "hole-in-the-head" vessel head erosion outage, Davis-Besse was offline. Adapting to such outages was routine, and FirstEnergy's operators imported power across high-voltage (345 kV) lines feeding into Cleveland from three directions: west toward Toledo and Detroit, Michigan; east toward Erie, Pennsylvania; and to the southeast toward Pittsburgh ran a dense transmission corridor of multiple lines.

Nevertheless, the loss of Davis-Besse was a headache for FirstEnergy staff: Where to find "reactive" power? While active power is easy to grasp-it supplies energy for heat, light and appliances-reactive power is a more mysterious force that maintains the magnetic flux of motors and pumps active power around the grid by supporting system voltage. Active power can be transmitted long distances over the 345 kV lines. Reactive power has a limited range, and it relies on local generating sources to prevent system voltage decay. Without Davis-Besse, the Cleveland area needed its other local generators to stay online to avoid voltage instability.

That didn't happen. At 1:13 pm, Unit 5 at Eastlake tripped. FirstEnergy operators began calling local generators including the Perry nuclear plant to provide more voltage support but were told by many that they were already at their reactive output limits.

At 2:02 pm, a 345 kV line in an adjoining control area tripped due to a ground fault. Carrying a heavy load, the transmission wires had warmed, drooped, and contacted a tree. At 2:27 pm, another 345 kV line between Cleveland and Pittsburgh tripped on a ground fault. Over the next hour, the line repeatedly burned back the tree, reset, and then burned the tree again.

Even at this point, all was not lost if operators had accurate information on the lost lines, but a computer glitch in an alarm system took it down without their knowledge. Only an hour later did an operator remark that the computer system was malfunctioning, "Nothing seems to be updating on the computers.... I think we've got something seriously sick."

While their indicators and alarms kept operators in the dark, signs of trouble emerged from distressed phone calls. At 3:35 pm, Perry's nuclear plant operator called to report a voltage "spike" on the unit's main transformer. The meter was "still bouncing around pretty good... so I know something ain't right." He called back again at 3:42 pm to say, "I'm still getting a lot of voltage spikes and swings on the generator.... I'm taking field volts pretty close to where I'll trip the turbine off.... I don't know how much longer we're going to survive." Calling back a third time, he said: "It's not looking good.... We ain't going to be here much longer and you're going to have a bigger problem." His meaning: Losing Perry could cause massive voltage instability and a cascading loss of other power generation units.

Ultimately, it was not Perry that started the cascade, it was untrimmed trees, lots of them. The early ground faults between 2:00 and 3:00 pm shifted loads to other transmission lines in the Cleveland-Pittsburgh corridor. They grew hotter, dipped more, and contacted trees. At 3:39 pm, a lower voltage 138 kV line had a ground fault, followed by 15 more in the next three minutes. Additional 345 kV lines tripped on tree contact between 3:45 and 4:05 severing transmission links to Pittsburgh and Erie.

JULY 2023 INSPECTOR NEWSLETTER 18 F8R IH'fD:NAL USE ONty Cleveland's remaining generating capacity had conservative protective setpoints and generators began tripping faster than the transmission system could shed electric load. With lots of demand and no local power sources, the city became a load blackhole sucking power from Toledo, its last link to the outside power grid. A huge counterclockwise surge of more than 3,500 MW circled Lake Erie from generators in New York, New Jersey, and Pennsylvania, across Niagara Falls and Ontario, into Detroit, south to Toledo, and turning east to Cleveland. Such dynamic power swings and system instability caused nearly 500 generating units to trip. Around 4: 10 pm, load shedding caught up and blackout islands formed from western Michigan, north to Hudson Bay, and east to New Jersey. Most of New England and Canada's Maritime Provinces were spared.

The blackout broke North American records and was the second largest in world history, affecting over 50 million people and 61,800 MW of electric load. While some areas of New York restored to power in a few hours, other areas waited 4 days. About 100 deaths were attributed to the blackout, Canada lost 0.7 percent of Its gross domestic product, and it may have contributed to the fall of the Ontario government in provincial elections.

A blackout on such a scale demanded a search for lessons learned. For electric power generally, there were clear lessons about common cause risk from something as prosaic as tree trimming. A post-blackout report noted that FirstEnergy's tree trimming practices could have been better but weren't different from most other operators. Needed were upgrades to industrywide practices, operator training, and mandatory grid reliability standards.

For nuclear power, the lessons of the blackout were not as obvious. Nine nuclear power plants tripped due to grid instability, but their safety systems performed as designed and on-site power was promptly reestablished. The NRC's 1988 station blackout (SBO) rule and licensee efforts to improve emergency power reliability had paid off.

The lessons gleaned from standardized plant analysis risk (SPAR) modeling were also mostly positive. NRC report NUREG/CR-6890 updated data on SBOs and Loss of Offsite Power (LOOP) events. It found that while LOOP frequencies had decreased significantly since 1986, LOOP durations had increased. Nevertheless, core damage frequencies for LOOP and SBO events were lower than previous estimates. Improved diesel generator performance was a major contributor to the positive trend.

The solution to longer LOOP outage times was not exclusively within the NRC's control. It required greater oversight from other federal agencies, such as the Federal Energy Regulatory Commission, improvements to NERC reliability standards, and action by Congress. Fortunately, all of those changes came to pass. The Energy Policy Act of 2005 made NERC's previously voluntary standards mandatory for U.S. electricity providers, and FERC strengthened penalties for producers that did not meet them.

In recent years, grid stability for an aging transmission system has remained an important issue. As measured by overall outage severity, the transmission system has improved measurably since 2018, but risk has increased from security threats and more extreme weather events that have grown in frequency, duration, and severity.

The blackout of 2003 served as a reminder of the intimate relationship between grid stability and nuclear power safety, as well as the need for the close cooperation among multiple actors. In assessing the blackout, the New York Times noted the fragility of the North American power grid. It was, the newspaper observed, like a canoe. "If just one person stands up, the boat will capsize. In this case, Ohio stood up." Hopefully, with the reforms of 2005 and continued vigilance, fragility will be replaced by resilience.

PNNL image of blackout from https://technet.pnnl.gov/sensors/electronics/projects/images/electronics477 large.jpg

JULY 2023 I NSPECTOR NEWSLETTER 19 POllt INT!lltNAL U!! ONLY Answer to "What's wrong #2" The picture on page 5 shows "temporary" lead shielding in contact with safety-related piping and directly above safety-related instrument tubing (a seismic II/I concern). While patiently waiting for operations to stroke a valve (related to a PMT activity), Jennifer England, FitzPatrick Resident Inspector, made the most of her time in this mezzanine area and questioned if the lead shielding had been evaluated for potential adverse seismic interactions. The shielding was originally installed in 1992.

The licensee's shielding procedure (effective June 6, 2006) required all existing long-term shielding to be evaluated by engineering and converted to permanent shielding. However, the associated engineering evaluation could not be located or provided. Following Jen's challenge, the licensee's corrective actions included entering the issue into their CAP, modifying the shielding to remove the contact with the safety-related piping and reducing the weight of the shielding, and performing a detailed engineering analysis of the corrected configuration. Jen also reached out to seismic subject matter experts in the regional office for support in assessing the issue of concern. (See inspection report 05000333/2022004 for more details on the associated Green NCV.) Inspector best practices: (a)

There is no substitute for being there and seeing firsthand. (b) Maintain a questioning attitude. Make sure that your field observations align with the design basis and good engineering judgment. ( c) When you know what "normal" looks like, then "abnormal" will jump right out at you. (d) Ensure that you share your field observations with Operations and/or Engineering, as appropriate, in a timely manner.

Do not analyze the condition for them or lower your standards. (e) Go the extra mile. This may involve reviewing the design and licensing basis, industry operating experience, operating and maintenance procedures, and/or the CAP database. (f) Phone a friend. Remember that the regional staff, other residents, NRR OpE Clearinghouse, and the NRR staff are excellent resources to tap to help put your issue in perspective. Great catch, Jen!

This quarter's "Catch of the Day" recognition goes out to Eben Allen. Millstone Resident Inspector. While performing a daily CAP review, Eben noted that on January 19, 2023, electrical maintenance personnel communicated that eight 6-volt batteries in the fire shutdown storage box had quality control issues and had an expiration date of December 2022. The expired batteries required Unit 2 to enter TRM 7.1..26, "Support Equipment, Appendix R Components," action statements because they are part of a TRM surveillance to inventory the fire storage box. The batteries were in the expired configuration from January 1, 2023, until they were replaced on February 2, 2023. The fire shutdown box is required to have eight 6-volt batteries available. Four 6-volt batteries are connected in series to form two sets of 24-volt battery packs. The 24-volt battery packs are required to implement AOP 2579AA, "Fire Procedure for Cooldown and Cold Shutdown, Appendix R, Fire Area R-1," to ensure cold shutdown is achieved within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Based on diligent digging, Eben identified that the fire shutdown Nominated by Joe Schoppy IRI/DORS/EB 1) storage box is inventoried once per refueling cycle and was last inventoried on January 3, 2022; the next scheduled surveillance was July 7, 2023; and the batteries were marked with an expiration date of December 2022. The licensee failed to take an appropriate action to ensure that battery functionality was maintained until the next scheduled surveillance in July 2023. During the January 2022 inventory, the surveillance form did not contain adequate documentation, comments, or corrective action addressing the eight 6-volt batteries expiration date. Additionally, Eben performed an independent inspection of the fire shutdown box on February 10, 2023, and identified other deficiencies with the contents of the fire shutdown box (including an out-of-calibration pyrometer, missing lanterns, and a missing radio charger. (See NRC Inspection Report 05000336/2023001 for more details.)

JULY 2023 INSPECTOR NEWSLETTER 20 F9R INTERPIAL USE 8NLV Inspector best practices: (a) Independently verify when possible. There is no substitute for being there and seeing firsthand. What did the licensee overlook or fail to consider? (b) Go the extra mile. This may involve reviewing the system history (including maintenance, STs, mods, & operating experience), the licensee's CAP database, design basis calculations, vendor manuals, operating procedures & logs, and the UFSAR. Is there a Pl&R aspect to the issue? (c) The devil is in the details. Sometimes, you've got to dig a little bit deeper to unearth hidden facts, discover additional clues, and/or identify disconnects. (d) Think outside the box. Maintain a questioning attitude when conducting plant status walkdowns. In particular, follow-up on missing/broken tamper seals or locking devices. With operations' permission and/or operator accompaniment, perform risk-informed inventory checks of storage locations (cabinets, boxes) for AOP/EOP required equipment, especially if not maintained locked and/or periodically inventoried by the licensee. Great catch, Eben!

(Nominated by: Eric Miller, FitzPatrick SRI}

This quarter's Eagle Eyes Award goes out to Jason Schussler, Ginna Senior Resident Inspector. While reviewing pictures to provide a second look to support the FitzPatrick resident inspector team, Jason identified lockwire installed incorrectly on a safety relief valve (SRV) pilot valve. The lockwire should be installed in an inverted S pattern between adjacent bolts such that if one bolt attempts to loosen it will tighten the adjacent bolt (and vice-versa). See picture below. The highlight in the schematic of the 3 stage SRV below shows the area of concern in What's Wrong picture #1 on page 2. The licensee initiated a corrective action issue report (IR) and performed an operability determination.

[

Background:

During a drywell closeout inspection in October 2022, the FitzPatrick residents found several SRV pilots installed with different configurations. Based on subsequent digging, the residents identified that NWS Technology provided FitzPatrick with incorrect drawings (Limerick's vice FitzPatrick's) during modification to 3 stage SRVs in 2018. As a result, engineering performed an evaluation to assess acceptability of using various combinations of lockwires, washers, or both together since the maintenance procedure was not clear. The FitzPatrick resident inspector team were performing a modification sample (71111.18) in the first quarter of 2023 to follow-up on the SRV mods (incorrect torque values on SRV pilots and use of Belleville washers and lockwire) and asked Jason for his help.]

Inspector best practices: (a) Do not underestimate the value of a thorough document review (this includes pictures, traces, and sequence of event recordings). (b) Independently verify when possible. What did the licensee overlook or fail to consider? (c) When you know what "normal" looks like, then "abnormal" will jump right out at you. (d) Go the extra mile. This may involve reviewing the system history (including maintenance, STs, mods, & operating experience), the licensee's CAP database, design basis calculations, vendor manuals, operating procedures & logs, and the UFSAR. (e)

Phone a friend. Remember that the regional staff, other residents, NRR OpE Clearinghouse, and the NRR staff are excellent resources to tap to help put your issue in perspective and/or help identify disconnects. Great catch, Jason!

(see next page for diagram and photo)

JULY 2023 INSPECTOR NEWSLETTER 21 F9R INTiRN.til. Uiii 0~11.¥ Hert'! tue bolt lig teM to U* e right If one toll tJ ::s to I<<>~ n lhrwgh brott on, I will 'ghltn lti. olh r bolt

~nd *re Ye:N.

Office of Nuclear Reactor Regulation Staff Supported the Federal Authority for Nuclear Regulation (FANR), United Arab Emirates (UAE) First Fire Protection Inspection at Barakah Nuclear Power Plant, Units 1, 2, and 3, Abu Dhabi, UAE ANR

~99-1-JI ci..../L§j..J.J ci..-:!.:iL:iH.I o 1 ! 6 II Fedel'al Authority for Nuci ar Regulation By Naeem Iqbal, Fire Protection Engineer/ Reliability and Risk Analyst, NRR/ DRA/ APLB On the sidelines of the 5th International Atomic Energy Agency Ministerial Conference on Nuclear Power in the 21st Century in Washington, DC, October 2022, the NRC Executive Director for Operations (EDO) and the Director of the Office of Nuclear Reactor Regulation (NRR) met with the UAE FANR Executive Team. During the meeting, NRC mutually agreed to expand cooperative activities with FANR in 2023. One of the FANR pre-identified areas of interest was fire protection inspection support. FANR informed the EDO that they planned to conduct the first fire protection inspection at the Barakah Nuclear Power Plant, Units 1, 2, and 3 (BNPP) in May 2023 and requested that the NRC provide one or two fire protection engineers to support the preparation of inspection and to participate in the inspection execution at the BNPP.

From May 15 - 26, 2023, the NRC staff from NRR, Division of Risk Assessment (DRA), provided the UAE regulator, FANR, inspection team with assistance, support, and execution of their first fire protection team inspection at BNPP. The two-week inspection activities included, one week inspection preparation at the FANR Headquarters located in Abu Dhabi, UAE. The second week was an onsite inspection at BNPP, located in the AI-Dhafra of the Emirate of Abu Dhabi on the Arabian Gulf, approximately 33 miles west-southwest of the City of Ruwais and approximately 190 miles from the Western Region of Abu Dhabi, UAE.

The objective of this inspection was to evaluate the BNPP fire protection program and determine if it has been fully implemented in accordance with the operating license and fire protection regulatory requirements as approved in the fire protection program and assess the plant's ability to achieve and maintain post-fire safe-shutdown capability. This assessment included a review of separation of safe-shutdown systems and the fire protection provided to assure this capability is maintained free from fire damage and the ability of plant fire protection features and programs to mitigate the consequences of a fire.

JULY 2023 INSPECTOR NEWSLETTER 22 F8R JNfERP.,til USE 8NL\\f The inspection scope was to walkdown fire areas/fire zones in company with the fire protection staff from Nawah Energy Company (Nawah) the licensee of the BNPP, and assess the fire protection structures, systems, and components, and administrative controls credited in the approved fire protection program can perform their licensing basis function.

A notification of fire protection Inspection and request for information letter was issued to the licensee one month before the inspection. The team inspection efforts were divided into six fire protection programmatic areas. The FANR inspection team consisted of UAE National engineers/inspectors from Headquarters Nuclear Safety Department and residents inspectors based full-time at the site.

During the inspection preparation, the UAE FANR engineers/inspectors reviewed the fire protection program documentation, the fire hazard analysis report, Updated Final Safety Analysis Report (UFSAR), the codes of records, licensee policies and procedures, and changes to the fire protection program and site since plant operation. In addition, in preparation for the inspection, the engineers/inspectors discussed the site fire protection program with the resident inspection staff, and any fire protection equipment availability or reliability problems (such as recurring failures or failures resulting in reportable events) that the licensee has experienced since the operation of Units 1, 2, and 3, that could impact operations. The engineers/inspectors interviewed llcensee staff and conducted walkdowns to observe the material conditions of fire protection structures, systems, and components and whether the licensee carries out its responsibility for maintaining fire protection systems, so they are available, operable, and in proper material condition to perform their intended safety functions.

During the onsite inspection, the engineers/inspectors interviewed licensee staff, conducted walkdowns, and reviewed design documentation, piping & instrumentation diagrams, test procedures and records, vendor manuals to verify, to the extent applicable, whether the licensee carried out its responsibility for testing and maintaining the fire protection systems and features, so they are available, operable, and in proper material condition to perform their intended safety function.

BNPP was designed and constructed in accordance with the U.S. regulations and standards. UAE FANR established its regulatory requirements of fire protection in FANR-REG-16, Article (22). "Fire Safety," to ensure that no undue risk is present to the public health and safety. The FANR deterministic/prescriptive fire protection rule is similar to the NRC fire protection regulation in 10 CFR 50.48. FANR Inspection Instructions OPS-08, Revision 1, "Fire Protection," focuses on evaluating the licensee's fire protection program, verifies the adequacy of its fire detection and suppression capability and controls for combustibles and ignition sources within the plant, and post-fire safe-shutdown capability, and licensing bases and those fire protection program elements that are covered by FANR regulations and guidelines. The inspection also assessed the performance of the fire brigade, readiness during an announced or unannounced fire drill, and plant fire brigade personnel training.

The guidance from the NRC Regulatory Guide 1.189, "Fire Protection for Nuclear Power Plants," is incorporated into BNPP fire protection program. In addition, FANR's Reactor Oversight Program (ROP) modeled after the NRC's ROP to inspect, measure, and assess the safety and security performance of the BNPP. FANR also adopted the NRC's Significance Determination Process (SDP) to determine the safety significance of inspection findings. The process described in detail in the NRC Inspection Manual, Manual Chapter 0609. The FANR follow the NRC inspection guidance in Inspection Manual Chapter (IMC) 2901, "Team Inspections. The ROP uses color-coded inspection findings and indicators to measure plant performance. The colors start at green and increase to white, yellow or red, commensurate with the safety significance of the issues involved. Inspection findings or performance indicators with more than very low safety significance trigger increased FANR oversight.

The inspection entrance meeting with the licensee was held on Monday May 22, 2023, to discuss the planned inspection activities. The FANR inspection team's potential observations and findings were communicated through debriefs scheduled in accordance with the inspection plan. The inspection team found several non-risk significance observations/deficiencies and were communicated to the licensee during daily debriefs. The exit meeting held on Friday, May 26, 2023. Based on the results of this inspection, FANR identified five preliminary issues that were evaluated under the fire protection SDP.

These issues were determined as having very-low safety significance (Green). Because the licensee-initiated condition reports addressed these issues, these violations are treated as Non-Cited Violations (NCVs). The inspection report will be issued in 30 days after the exit meeting and NCVs will describe it in the inspection report.

The FANR Nuclear Safety Department Director was highly complementary of the NRC staff and conveyed, "I have to admit that this has been one of the most valuable experiences, with many lessons learned to be captured in terms of knowledge shared by the NRC staff, particularly with our young UAE national engineers/inspectors. The completion of this inspection, as well as the observations made by our inspection team, highlighted the value of information exchange that led to the successful execution of this inspection.,,

Read the full article at: ML23187A632.

JULY 2023 INSPECTOR NEWSLETTER 23 F8R IN'fERNilrL USE 8NLV Inspector Mailbox Send your questions and comments to the Inspector Mailbox. The Newsletter Edltorlal Staff Is happy to answer any newsletter questions, comments or concerns thal you may have.

lnspectorNewsletter@nrc.gov NRC Inspector Field Observation Best Practices http://wwwnrc.gov/reoding-rm/doc-collections/nuregs/brochures/br0326

/br0326.pdf Support Our Troops Thank you to all of you who have served and to the significant others who hove supported them.

Special "Shout Out & Thank You" to Newsletter Editorial Board We are looking for Joe Schoppy, RI articles, as well as your feedback!!/

Steven Smith, RII Contact any one of us by using the new Inspector Newsletter e-mail account!//

Aaron Mccraw, RIii Leanne Flores, RIV Madeleine Arel, HQ Many Thanks to Our January 2023 Newsletter Contributors!

Eben Allen, Harry Anagnostopoulos, Lee Brookhart, Maury Brooks, Lauren Bryson, Neil Day, Jennifer England, Jack Freeman, Chris Highley, Tom Hipschman, Naeem Iqbal, Eric Miller, Mike Ordoyne, Scott Rutenkroger, Jason Schussler, Atif Shaikh, Thomas Wellock, and Joe Schoppy, You can con1ribute to the quarterly Inspector Newsletter! Send an inspection related article to lnspectorNewsletter@nrc.gov ease rememb ur nomination arter1y Eagl, E the Day, and E minations.

The Editorial Board encourages staff to get permission prior to using any photos that appear in an Inspector Newsletter article. Photos that appear in the Inspector Newsletter are potentially subject to FOIA requests. Inspectors should not convey to the licensee that such photos will be kept confidential.

all of the NRC employees currently 1----------------------------------------1 Other Useful Information:

serving our country on Active Duty.

Stay safe and come home soon!

Welcome Home to all of the NRC employees who have recently returned home to us safely! We're glad to have you back and inspecting with us!

Quarterly ROP Changes?

No new ROP Changes this quarter.

If you'd like to read about summaries of (very high level) significant (not editorial) recent changes in ROP guidance since the lost newsletter let us know and we'll include them!

end us your feedback and your articles/ You could be one of the contributors to the next Inspector Newsleffer!

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https://usnrc.shorepoint.com/teoms/N RR-Inspector-Newsletter or find the current and previous newsletter articles on Shore Point Providing useful information to our inspectors, by our inspecto-rs!

FOR l~nrnu*AL Y&E O~UY

APRIL 2023 INSPECTOR NEWSLETTER 1

Inspector Newsletter APRIL 2023 Providing useful information to our inspectors, by our inspectors!

Contents Deja Vu All Over Again....................... 1 ANO Pressurizer Heater Capacity -

When MeeHng a TS Doesn't Mean CondlHons are Acceptable................ 3 Current Status of Vogtle Units 3 & 4 Initial Test Program........................... 4 What's Wrong with This Picture #1 ?.... 5 TEAMWORK MAKES THE DREAM WORK

............................................................... 5 What's Wrong With This Picture #2?.... 7 Fire Protection Knowledge Management and Knowledge Transfer Articles in Nuclepedia.......... 8 The OpE Fishing Hole........................... 9 Inspectors Weigh In on Fire Protection Program Change............................... 10 What's Wrong With This Picture #3?.. 12 Catch of the day................................ 13 Answer to "What's wrong #1 "........... 14 Eagle Eyes Award.............................. 14 Answer to "What's wrong #3"........... 16 Chicago PIie lnteresHng facts........... 16 Commission Reinstates Sample Requirements for Post Maintenance Testing (PMT) and Surveillance Testing (ST)....................................... 22 FOR ltHERNAL liSE ONLY Deja Vu All Over Again by Jason Schussler, Ginna Senior Resident Inspector

Background:

Containment spray recirculation valve 868D was added to the system in a 2009 engineering change package as part of a full flow recirculation test modification.

The valve has two functions, first the valve seat ensures fluid flow to the containment spray ring. The second function is fulfilled by the valve body and seat which provide a containment isolation boundary. Specifically, the valve is part of the ' B' containment spray pump discharge pressure boundary and is a containment boundary valve for penetrations 105 and 109. In 2013, the licensee identified a borated water leak on valve 868D. The condition was entered into the CAP and the valve was added to the boric acid corrosion control program (BACCP). Valve 868D was monitored as part of the BACCP from June 2013 through February 2021. During that monitoring period, the licensee performed two corrective maintenance (CM) work orders to reapply torque at the bonnet to body mechanical joint. The first CM work order was completed in 2015 and the second one performed after the resident inspectors ident itied that the valve was leaking again in 2018. In June 2022, the inspectors identified a residual heat removal valve (712A) that had deposits of boric acid on the valve body from a previous borated water leak (this green NCV was documented in inspection report 05000244/2022003 and discussed on page 7 of the January Inspector Newsletter).

Inspector value-added: During extent-of-condition boric acid walkdowns in August 2022, the inspectors identified that once again valve 868D had dry boric acid deposits on the valve body and promptly informed the BACCP engineer (see pies below). The licensee entered this condition into their CAP and evaluated the leak in accordance with their BACCP. Additionally, the licensee is committed to an edition of the ASME Code which defines valve 868D as in scope. As a result, the applicable articles of the Code further state requirements for examination, inspection, repair, and corrective actions.

Subsequently, engineering determined that the borated water leak was t hrough the valve body itself and likely due to original casting porosity and likely an original manufacture flaw. It was noted that the flaw was on the downstream side of the recirculation flow path, and above the pressure boundary function of the valve seating surface. As a result, the valve seat would still maintain flow to the spray ring, but containment penetrat ion 109 was reduced from two valves providing isolation to one.

Additionally, valve 868D is the second containment Isolation boundary for penetration 105, and because of this deficiency, that penetration was also reduced from having two valves provide isolation, to one. These conditions required the licensee to enter Technical Specification action statement 3.6.3.A for penetrations 105 and 109. The licensee completed actions to verify that the affected penetration flow path was isolated by at least one closed valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and once per 31 days thereafter. Lastly, the licensee completed corrective maintenance to replace the leaking valve on December 1, 2022. It is interesting to note that, due to the leak location relative to the seat, this leak only revealed itself during quarterly full flow recirculation surveillances.

[See NIRC Inspection Report 05000244/2022004 for more details.]

(see photos and Best Practices on next page)

APRIL 2023 INSPECTOR NEWSLETTER Jason Inspecting the valve from the aux building floor below Inspector Best Practices noted above:

2 Independently verify when possible. There is no substitute for being there and seeing firsthand. What did the licensee overlook or fail to consider?

FOR INT&APl~I. USE 8NL¥ Looking down on the leak from above. [Note:

Engineering used a selfie stick to put their camera phone up high and took a picture looking downward. Makes it easy to meet the rule in the RCA that going above 7' required RP support for ALARA concerns. Good use of technology by engineering.]

Look at things from different angles, get down on the ground if necessary. However, make sure that you're fully aligned with the licensee's expectations before climbing (especially in the RCA).

When you know what "normal" looks like, then "abnormal" will jump right out at you.

Ensure that you share your field observations with Operations and/or Engineering, as appropriate, in a timely manner. Do not analyze the condition for them or lower your standards.

Go the extra mile. This may involve reviewing the system history (including maintenance, STs, mods, &

operating experience), the licensee's CAP database, design basis caloulations, vendor manuals, ASME Code requirements, and the UFSAR.

Good inspection practices include the age-old question "have you considered the extent-of-condition?" This extent-of-condition review may uncover a programmatic issue and/or increase the risk significance depending upon the condition of other similar SSCs.

Follow up periodically to ensure corrective actions adequately addressed the problem. Are the licensee's corrective actions addressing causal factors or just symptoms?

Maintain a questioning attitude. Albert Einstein defined insanity as doing the same thing over and over again and expecting different results.

Inspecting is not a "once and done" proposition. The more often you're out there and about, the greater the odds of encountering abnormal conditions. In the case above, the inspectors weren't particularly satisfied with the actions to re-torque the joint in 2018. However, the inspectors couldn't specifically say it was "wrong" to do that corrective action, especially since it appeared to have worked for a few years. However, simply re-torquing a mechanical joint didn't do it for Jason, so he made it a practice to keep an eye on the mechanical joint and valve on his plant status walkdowns (which eventually paid dividends).

Remember, the "I" in "SRI" stands for "inspector." In the key leadership role of SRI it is important not to allow paperwork, reports, and administrivia to keep you from inspecting in the field, especially considering your inspection experience and capability to transfer the knowledge to other less-experienced inspectors. We need you in the field!

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APRIL 2023 I NSPECTOR NEWSLETTER 3

POiit INT!llt:NAL U!! ONLY ANO Pressurizer Heater Capacity - When Meeting a TS Doesn't Mean Conditions are Acceptable Tim DeBey completed a surveillance inspection sample of the ANO-2 pressurizer heaters using IP 71111.22 and noted the licensee barely met the technical specification requirements for minimum heater capacity. Tim decided to investigate ANO Unit l's pressurizer heater requirements to see if there were concerns.

ANO-1 pressurizer heater requirements are contained in TS 3.4.9.b, which requires a minimum of 126 kW of engineered safeguards bus powered heaters to be operable. Tim determined that the licensee had met the surveillance requirement, but he chose to dig deeper and investigate the TS bases and the USAR. The basis for the technical specification stated, in part, that the pressurizer heaters are used to maintain pressure in the RCS so reactor coolant in the loops is subcooled and that this function must be maintained with a loss of offsite power. The inability to maintain subcooling margin under natural circulation flow could lead to loss of single-phase natural circulation and decreased capability to remove core decay heat. If natural circulation cooling was not possible, then operators would need to initiate the emergency core cooling system and provide once-through cooling through the pressuriz,er PORV.

Tim found that 126 kW was chosen by the licensee (and most Babcock and Wilcox PWRs) in response to an Action Item from the Three Mile Island Accident which required PWRs to provide a set of pressurizer heaters, powered by redundant emergency power sources, to establish and maintain natural circulation cooling at hot standby conditions following a loss of offsite power. The NRC never required adding a surveillance test to measure pressurizer ambient heat loss, NRR based its approval of the 126 kW on an ambient heat loss test performed in 1975 which had a result of only 82.75 kW.

However, Tim found that the last pressurizer ambient heat loss test (performed in 1992) measured as 183 kW.

Tim initiated discussions with the NRR project manager, the senior reactor analyst, and a TTC training instructor for assistance in reviewing the licensing basis, the risk significance, and operational impact using the TTC simulator. In the end, the agency concluded that ANO was in violation of a 1980 Confirmatory Order that required implementation of the pressurizer heater TMI Action Item and a Greem NCV was issued in the residents' quarterly inspection report (050000313/2022003). During the fall 2022 ANO-1 refueling outage, the residents identified that there was insulation missing from the dome of the pressuriz,er. In response, the licensee found even more insulation was degraded or missing.

Tim's efforts proved that just meeting a TS doesn't always mean the condition is acceptable.

This finding highlights the importance of inspector questioning attitude and verifying the design and licensing basis. Tim demonstrated the NRC values of Integrity, Service, Excellence, Cooperation and Commitment by using his technical training, questioning attitude, and communication skills to independently evaluate (and educate) the licensee's design basis. Tim also demonstrated the Principles of Independence, Clarity and Reliability by continuing to pursue the resolution until the licensee understood the deficiencies. Congratulations on the Region IV Reactor Star, Tim!

Letters to the Editop Thank you to all those who took the time to provide feedback on the January Newsletter. A special shout-out to Kelly Korth (one of the many outstanding instructors at the TTC), who provided the following feedback on the acronym challenge: There is another "embedded" acronym (well, an acronym that contains two other acronyms) that came out in the latest revision of the BWROG EPG/SAGs. They establish the lowest pressure that licensee's should maintain during an ATWS event to avoid excessive power oscillations and potential fuel damage. It is called MARP: Minimum ATWS (anticipated transient without scram) RPV (reactor pressure vessel) Pressure. BTW, the SCRAM (safety control rod axe man) had a name: Norman Hilberry. He later said "I felt silly as hell. This was a lot of nonsense." Kelly also provided a copy of an email that he had sent out years ago containing more interesting facts on the first nuclear chain reaction. See his article at the end of this newsletter. Thank you, Kelly!

APRIL 2023 I NSPECTOR NEWSLETTER 4

F8R IHTEAPIAL USE 8Plb¥ INVOGTIAE...

Current Status of Vogtle Units 3 & 4 Initial Test Program By Scott Egli The licensee had made great strides in moving the plant toward commercial operations. Some of the major activities completed to date include initial fuel load October 13-17, 2022, initial criticality on March 6, 2023, and entering Mode 1

(>5% power) on March 9, 2023. Our resident inspectors along with regional inspection support continue to observe the licensee's performance as they progress the unit through start-up testing inspection activities as well as ROP baseline inspection activities.

We have witnessed significant activities including the remote shutdown workstation (RSW) test from Mode 3 to Mode 5 as well as the rapid power reduction system test. The remote shutdown station test demonstrated that the reactor coolant system could be cooled down using only the controls in the RSW from Mode 3 to Mode 5. The rapid power reduction test demonstrated the system would drop the correct control rods, when required, for a turbine trip or a large load rejection to maintain the reactor online. We also witnessed initial criticality and low power physics testing where the licensee diluted to criticality and then held power less than the point of adding heat ( < 1 % ) while they performed tests such as determination of control rod worth and the moderator temperature coefficient.

Although the licensee has made progress toward commercial operations, Unit 3 has experienced several challenges after fuel load-which had to be addressed resulting in scheduling delays for initial startup and ultimately the push to commercial operations. For each of these challenges, the resident and regional inspection staff have done an outstanding job ensuring the licensee has taken the proper corrective actions and performed operability reviews to verify the plant is safe to continue with start-up testing activities. Some of the challenges included:

Abnormal vibration indications on the Loop 2 ADS Stage 4 piping. Upon investigation it was determined that the piping supports were not installed per design requiring the licensee to take the unit to Mode 5 to initiate repairs as well as submit a license amendment to remove a number of LCOs prior to initial criticality.

Discovery of leakage past the Passive RHR Heat Exchanger outlet valves which required the licensee to bring in the vendor and perform multiple adjustments to the valves to bring the leakage within acceptable values.

A flange leak on the IRWST injection line squib valve required the licensee to take the plant to Mode 5 on two occasions and install a freeze seal to perform repairs.

More recently, the licensee has faced several challenges while trying to synchronize the main generator to the grid for the first time. In preparation for synchronization, the licensee was performing automatic voltage regulator (AVR) testing when the main generator tripped upon detection of a fault in the AVR circuit. This resulted in the reactor automatically tripping due to the loss of two reactor coolant pumps when their electrical buses failed to automatically fast transfer after the main generator tripped. Resident staff responded to the site after the trip to ensure proper actions were taken to place the unit in a safe condition.

Subsequently to the turbine/reactor trip, the main generator tripped three times, without a reactor trip, while attempting to synchronize to the grid. Causes of the generator synchronization issues included incorrect relay settings with the output breaker, wiring issues with the output breaker current transformer, wiring issues associated with the plant control system, and most recently a malfunction of the digital turbine control system right after the generator was synchronized to the grid. The cause of this latest event is under investigation.

We will continue to witness start-up testing activities after the generator is placed online and the plant begins to raise power through the various testing plateau power levels of 25, 50, 75, 90, and 100% power.

Some of the more significant upcoming tests include:

APRIL 2023 I NSPECTOR NEWSLETTER 5

POiit: IIH'fRNlcL USE 8NLY Remote shutdown workstation test at 25% power (Mode 1 to Mode 3),

Loss of offs1te power test at 50% power, Turbine/Generator trip from 100% power without a reactor trip, and 100% load rejection test without a turbine/generator or a reactor trip While the inspectors continue to witness the licensee's performance on Unit 3 as they move the plant through start-up, the inspectors must also continue to be vigilant with the activities on Unit 4 which is currently in the midst of hot function testing (HFT). HFT is a major milestone where systems will be tested for the first time demonstrating the systems will perform in an integrated fashion. HFT has various RCS temperature test plateaus from ambient temperature up to SS7°F and then returning to ambient. Unit 4 should reach full temperature and pressure by early to mid-April and should complete HFT by mid to late May.

What's Wrong with This Picture #1?

TEAMWORK MAKES THE DREAM WORK Our story begins on November 17, 2022, with Earl Bousquet, Millstone Resident Inspector, performing an internal flood inspection (71111.06) in the U3 engineered safety features (ESF) building. During his ESF building walkdown, Earl observed that a previously identified service water (SW) leak from the flange of the 'A' train ESF building air conditioning unit supply check valve (3SWP*V705) was now dripping onto the 26-inch 'A' train SW supply piping below. Earl "pulled the string" on the old deficiency tag hanging on 3SWP*V705 and noted that the condition was documented in the corrective action program (CAP) as condition report CR1205520 on August 12, 2022. The CR was closed to the work management process to replace the check valve during a future refueling outage. Earl also noted that the CR's operability screen had stated the ESF air conditioning unit check valve was leaking onto the SW pipe below and concluded that the condition did not impact the 'A' train of SW. However, the resident inspectors (Earl and Justin Fuller, Millstone SRI),

challenged this conclusion as the U3 SW ultimate heat sink is Long Island Sound, which can be corrosive to susceptible carbon steel piping. [KT - The U3 SW system provides cooling water for heat removal from the reactor plant auxiliary systems during all modes of operation and from the turbine plant auxiliary systems during normal operation. This portion of the SW system is safety-related and seismic category I. This portion of the SW system operates in support of ESF systems acting to mitigate the consequences of accidents.]

At this point in the story, Earl had to hand the inspection baton off to Justirn, as Earl departed for Naval Reserve duty. The longstanding nature of the leak and the concern for the carbon steel piping below prompted Justin to perform additional

APRIL 2023 INSPECTOR NEWSLETTER 6

F8R HffEAPIAL USE e,1b¥ walkdowns of the condition in the ESF building. Justin observed that the insulation surrounding the 26" SW pipe had trapped the leakage from 3SWP*V705 above, and the condition of this pipe spool was not apparent with the insulation installed. In response to the NRC questions (since inspectors should not remove insulation on their own), the licensee removed the insulation and noted excessive corrosion of the piping and adjacent fillet weld between the pipe spool and the slip-on flange. The licensee took prompt action to clean the pipe and slip-on flange weld, perform ultrasonic thickness measurements of the pipe spool base metal, and conduct a visual Inspection of the fillet weld. Through performance of these inspections, the licensee determined that the pipe wall had been reduced in several locations to approximately 75 percent of the nominal wall thickness but remained above the ASME Code minimum wall thickness. However, the fillet weld between the slip-on flange and the pipe spool had corroded to a point, that in several locations, the weld did not meet the ASME Code requirements.

Because the weld was noncompliant with the Code, the licensee entered Technical Requirement 3.4.10, "Structural Integrity - ASME Code Class 1, 2, 3 Components," on December 6, 2022. On December 7, 2022, the licensee completed a structural integrity evaluation that was documented in an engineering technical evaluation. Therefore, the licensee determined that structural integrity was maintained, and the 'A' train of service water was OPERABLE. The inspectors reviewed this engineering technical evaluation and associated operability determination, with regional support from Nik Floyd (Region I/DORS/EB1) and did not identify any concerns with the licensee's methodology. The licensee's corrective actions included entering the NRC-identified issue in the CAP and creating corrective action assignments to restore the fillet weld profile to Code required minimum at the next available opportunity when the pipe is out of service (i.e., 'A' train service water scheduled refueling outage). In the interim, the licensee planned to coat the SW pipe to protect it from further corrosion. [See NRC Inspection Report 05000423/2022004 for more details.]

Great teamwork, Earl & Justin!

Inspector Best Practices noted above:

When you know what "normal" looks like, then "abnormal" will jump right out at you. However, sometimes you have to challenge what "normal" looks like if it doesn't appear to align with the design basis and good engineering judgment.

Follow the string, extension cord, fluid trail, staining, or anything out of the ordinary. There's usually a story waiting to be told.

Throw out the challenge flag when it doesn't seem right or if it doesn't pass the reasonableness test.

Maintain a questioning attitude. It is difficult to arrive at a different end point (conclusion) if you travel down the same identical path as the licensee. In this case, what are the potential adverse impacts of water dripping on the piping below?

Go the extra mile. This may involve reviewing the system history (including maintenance, STs, mods, & operating experience), the licensee's CAP database, design basis calculations, vendor manuals, the ASME Code, and the UFSAR.

Follow up periodically to ensure corrective actions adequately addressed the problem. In addition, for identified deficiencies that are not promptly corrected, follow up periodically until the issues are resolved to ensure conditions do not degrade further.

Phone a friend. Remember that the regional staff, other residents, NRR OpE Clearinghouse, and the NRR staff are excellent resources to tap to help put your issue in perspective.

What Questions Have You Asked Today?

APRIL 2023 I NSPECTOR NEWSLETTER 7

F8R INTERNAL USE 8NLY What's Wrong With This Picture #2?

What's wrong with the above picture? After pondering the picture for a few minutes, flip back to the Eagle Eyes article on page 14 for the answer.

Dressed for success - Veronica Fisher, NRAN, verifying a component ID during walk down of the Unit 2 containment at Calvert Cliffs (making the most of her rotation to RI/DORS/EB1 ).

APR.IL 2023 INSPECTOR NEWSLETTER 8

Fire Protection Knowledge Management and Knowledge Transfer Articles in Nuclepedia F9R Ul"FliRPl~lo. US& 9Nlo.}f Naeem Iqbal, Fire Protection Engineer/Reliability and Risk Analyst, NRR/DRA/APLB The following link to Nuclepedia contains knowledge management/knowledge transfer articles and captures the nuclear power plant fire protection knowledge, operating experience, technical, regulatory, and licensing basis documents. This paperless link provides the convenience of a single archive containing over 100 electronic documents for quick retrieval.

This Nuclepedia page provides access to all relevant documents from the last 40 years or so; links include the following:

both National Fire Protection Association (NFPA) 805 and Non-NFPA 805 plants licensing basis documents, triennial inspection reports, inspection procedures, enforcement guidance documents, fire protection for decommissioning reactors, license renewal safety evaluation reports, power uprate safety evaluation reports regulatory guides, NUREG-0800 SRP fire protection sections, Branch Technical Positions, fire protection Generic Communication {Generic Letters Information Notices, Regulatory Issues Summaries),

SECY Papers, fire protection Technical Interface Agreements, NFPA 805 Frequently Asked Questions, NFPA code of records, NUREGs reports, Office of Inspector General and Govemment Accountability Office audit reports, Commission briefings, fire protection knowledge management topics and presentations, and fire protection training etc.

The fire protection information contained in the Nuclepedia link will assist regional and resident inspectors when conducting fire protection inspections and retrieving fire protection relevant information and oversight activities. This page hopes to enhance the inspector's ability to apply the appropriate regulatory requirements, licensing basis, and guidance documents to individual nuclear power plants.

Click the picture below to access articles. Please direct any questions and/or feedback regarding these l(b)(4) pages to: Naeem Iqbal, Naeem.lqbal@nrc.gov.

l I Fire Protection Knowledge Management Knowledge Transfer

APRIL 2023 I NSPECTOR NEWSLETTER 9

F8R UH'ERNAL USE ONLY The OpE Fishing Hole OpE Hub (Check it out!) - https://usnrc.sharepoint.com/teams/NRR-Operating-Experience-Branch/OpE%20Hub/index.aspx The NRR Operating Experience (OpE) Branch will use this space to provide periodic updates on topics such as:

Data Access and Data Analytics tools for inspectors and other staff Recent and in-process OpE products (COM Ms, Smart Samples, generic communications, etc.)

OpE Clearinghouse Overview:

The Clearinghouse Team is a centralized multi-office team (NRR, RES, 01, NSIR) that meets twice a week to review OpE.

The goal of the Clearinghouse is to get the right information to the right people in a timely manner. Our team sere-ens the inputs depicted in the diagram below and then informs stakeholders via the products summarized in blue.

Inputs DomHtlc OpE: Industry Immediate Nouliu11lon Ri,poru.

Licensee EVllnl Reports*

Oefen/Noncompliance Reports*

Dom**tlc OpE: NRC Inspection Findings*

Regional Safety Calls -~

Studies/Trends Non-Nuclear Events lnttrn1tlon1I Op£ Working Groups Conferences IRS and INES Technical Review Group Overview:

NRC OpE Program OpE Program Generic Communication an OpE Brenc OEB d

h(I

)

Screening Communication Evaluatlon Application i

Store OpE Data r+

Products lnlormlns Stahholdert Generic Communica11ons*

Internal Products 111G Reports Of)E Brie0ngs O~shhoards lnAutncln1 As*ncv Pro1ram, f-+

Inspection*

Licensing*

Rulemaking*

Taklnc Rqulotory Action, Information Request*

~

Orders*

Technical Review Groups (TRGs) are a significant contributor and source of valuable evaluation and feedback.

TRGs are comprised of experts across the agency. Currently, there are 40 focused TRGs ranging from specific plant systems (AFW, ECCS, Electrical Power etc.), to human performance and safety culture. TRG's perform periodic reviews of current OpE with a focus on identifying potential significant OpE, adverse OpE trends, and/or OpE with a common theme that may warrant further NRC review or action, such as communication.

Are you interested in joining a specific TRG? Check out our SharePoint Site: NRR TRGs OpE COMM Distribution: Another tool in your inspector handbag:

Interested in receiving a periodic brief overview when significant issues across Industry occur concerning events, adverse trends, or issues of general interest to NRG technical staff, managers, and inspectors?

Check out our OpE Comm page and request to become a recipient here: NRR OpE COMM Forum. Simply click on "Subscribe to OpE COMMs." To review past OpE COMMs, simply click on "See All COMMS."

Recent Generic Communications IN 2023-01: Risk Insights from High Energy Arcing Fault Operating Experience and Analysis (ML22326A204)

APRIL 2023 INSPECTOR NEWSLETTER 10 F9R DITiRNAI. Uii O~ll¥ IN 2023-02: Reporting When a Fixed Gauge Shutter is Stuck in the Closed Position (ML22326A295)

Draft RIS 2014-06 R1: Consideration of Current Operating Issues and Licensing Actions in License Renewal (ML22024A172)

Contact and Feedback Please reach out to a member of the branch with any questions or feedback.

OpE Branch Points of Contact Region I Paul Laflamme INPO Brian Benney Region II Robert Beaton /

Part 21 Paul LaFlamme Adam Lee, NRAN Region Ill Brian Benney /

Generic Communications Brian Benney/ Phyllis Clark Lauren Bryson, NRAN Region IV Chris Speer Dashboards Jason Carneal / Rebecca Sigmon Branch Chief Lisa Reoner 50.72 / 50.73 Chris Speer, Paul Laflamme Inspectors Weigh In on Fire Protection Program Change By Len Cline, Senior Reactor Inspector, RI/DORS/EB2 The requirement: NFPA 805 Chapter 3.2.3(1) requires that procedures be established to accomplish inspection, testing, and maintenance for fire protection systems and features credited by the fire protection program. Testing requirements for fire protection systems that protect equipment needed to achieve and maintain a safe and stable condition are contained in the Technical Requirements Manual (TRM) and plant procedures mandate the testing process. TRM limiting condition for operation 15.7.7, Halon System, states that equipment in the cable spreading rooms, switchgear rooms, DAS computer rooms, and cable chase lC and 2C is relied upon to achieve and maintain safe and stable conditions and is protected by Halon. NFPA 12A, Halogenated Extinguishing Agent Systems Halon 1301, 1971, is the code of record for the Halon syst ems installed at Calvert Cliffs. Section 1715 directs that the weight and pressure of refillable containers shall be checked semiannually and if a container shows a loss in net weight of more than 5 percent, it shall be refilled or replaced. The standard also states that the goal of inspection and testing shall not only ensure the system is in a full operating condition, but shall also indicate the probable continuance of that condition until the next inspection. TRM technical verification requirement (TVR) 15.7.7.2 requires that halon storage tank weight (level) is verified >95 percent of full charge every six months. The weight associated with a full charge for the halon bottles is indicated on the nameplate for each bottle and most bottles are charged greater than the full charge amount when received from the vendor. Prior to May 2019, the licensee satisfied TVR 15.7.7.2 by weighing the halon bottles using a scale.

The opportunity: On May 22, 2019, the licensee revised their halon bottle weight verification procedure by adding an alternative method for determining the weight of halon in the bottles. It used an ultrasonic instrument (Coltraco Ultrasonics, Porta level Max) to measure level and then calculated bottle weight by applying conversion factors for temperature and t.ank volume from the halon system vendor manual to the measured level.

Inspector value-added: The inspectors determined that the halon system vendor manual included a method for determining bottle weight by measuring level and that guidance in Electric Power Research Institute (EPRI) 1006756 for fire protection equipment surveillance optimization and maintenance also acknowledged that measuring level can be an alternative to weighing the halon bottles. However, the inspectors noted that the method described in the licensee's new procedure did not include the same steps as the method used in the vendor manual and EPRI 1006756 did not provide details on how to perform the alternate level method. However, both the vendor manual and EPRI 1006756 emphasized the importance of correlating the measured level to a past known value obtained by weighing the container and this was a step that the inspectors identified as missing from the licensee's new procedure revision. The inspectors questioned whether the licensee's revised procedure and weighing the bottles on a scale were functionally equivalent because the licensee's revised procedure did not directly align with the vendor manual and EPRI guidance. Additionally, the inspectors reviewed the halon bottle weights recorded during the last three performances of the new procedure and identified significant variability considering an acceptance criterion of less than 5 percent reduction from full charge. For

APRIL 2023 I NSPECTOR NEWSLETTER 11 FOR IN I ERNAL USE ONLY example, the inspectors identified that in 6 of the 18 bottles supplying halon to the switchgear rooms, the calculated weight of halon based on measured level increased on average by more than 5 percent without being recharged between the first and last measurement of the last three measurements.

Regulatory leverage and additional inspector value-added: The Calvert Cliffs NFPA 805 license condition allows changes to approved fire protection program elements without NRC prior approval when an engineering evaluation demonstrates that the alternative to the Chapter 3 element is functionally equivalent to the previously approved methods for the corresponding technical requirement. The licensee's procedures clearly state that changes to fire protection program implementing procedures are reviewed to assure that fire protection capability is maintained at acceptable levels and that a change does not adversely impact post-fire safe shutdown capability.

Specifically, the 50.59 Applicability Review Form for the procedure revision identified that the proposed procedure change involved a change to the Fire Protection Program and directed a Fire Protection Change Regulatory Review. The inspectors identified that, contrary to the requirements of the Fire Protection Program, the licensee did not complete this review prior to implementing the procedure revision and therefore did not demonstrate that the proposed alternative method for determining the weight of halon bottles was functionally equivalent to previously approved methods.

Significance: On November 22, 2022, in response to inspector concerns, the licensee measured the weight using a scale and ultrasonic level measurement in eight spare halon bottles. The difference between these two measurements for four of the eight bottles was greater than 5 percent, and the difference was greater than 13 percent on two of the bottles. The variation in measured weight using the ultrasonic level measurement was also not always in the conservative direction. Given that the design requirements for the halon system require that a bottle showing a loss in net weight of more than 5 percent of full charge be replaced, the inspectors determined that variation seen in the halon weight determined using the new procedure revision was potentially significant. Without an appropriate engineering evaluation to confirm that the licensee's revised procedure for determining halon weights was functionally equivalent to previously approved methods, the licensee could not ensure that the revised procedure would accurately identify bottles containing less than 95 percent of full charge.

Leaving bottles with less than the required charge installed in the halon system could adversely impact the halon system's functionality. The halon system is used to protect equipment relied upon to achieve and maintain safe and stable conditions from fire damage.

Corrective actions: To confirm current halon system functionality based on the concerns raised by the inspectors, the licensee weighed over 50 percent of the halon bottles using a scale and each of the bottles weighed exceeded the TVR acceptance criteria of 95 percent of full charge. The licensee Initiated corrective actions to weigh all remaining bottles using a scale, and to address the surveillance test procedure concerns and associated performance deficiencies. [See NRC Insp.ection Report 5000317 &

318/2022010 for more detalls.J Shout-out to Naeem Iqbal (Fire Protection Engineer/Reliability and Risk Analyst, NRR/DRA/APLB):

The team reached out to Naeem via Teams during the onsite weeks, at times early and late in the day.

He provided help to identify Calvert Cliff's specific licensing basis requirements for Halon. He also helped the team to track down the industry standards to which the licensee was committed and what was actually expected to comply with the standards. Naeem was particularly helpful because neither the inspection team nor the licensee had expertise in Halon system design and maintenance. Great teamwork, Naeem!

APRIL 2023 INSPECTOR NEWSLETTER Inspector Best Practices noted above:

12 fOR INT&APl~l USE 8NLV

Apply "The Sesame Street Method" - which one of these things is not like the other, and why?

Keep a low threshold and do not easily let the licensee "explain it away." If it does not seem right...it probably isn't. Be professional, but be doggedly persistent when it comes to nuclear safety.

Make the licensee show you why it makes sense; and if it doesn't make sense to you, keep asking questions until it does.

Always remember the inspector "lifeline" to headquarters experts. Know who the experts are and reach out to them early and often when needed. One lesson learned for this inspection was that as soon as we realized that neither we nor the licensee were experts in this area and the licensee did not have the expertise to competently answer our questions, we should have reached out to headquarters. It may have helped us to close out the issue earlier and without as much individual effort.

Maintain a questioning attitude. Make sure that your field observations align with the design basis and good engineering judgment. Are* the associated PMs and/or functional tests appropriate, properly implemented, and adequate to ensure continued operability/functionality of the SSC?

Go the extra mile. This may involve reviewing the system history (including maintenance, testing, mods, & operating experience), t he licensee's CAP database, design basis calculations, vendor manuals, procedure changes, and industry guidance.

The devil is in the details. Sometimes, you've got to dig a [little bit deeper to unearth hidden facts, discover additional clues, and/or identify disconnects.

What's Wrong With This Picture #3?

What's wrong with the above picture? After pondering the picture for a few minutes, fli back to for the answer.

APRIL 2023 INSPECTOR NEWSLETTER 13 fOR INTiRN,,L US& 9Nb¥ This quarter's "Catch of the Day" recognition goes out to Jennifer England, FitzPatrick Resident Inspector. On February 1, 2023, Ms. England reviewed battery testing information associated with the 419 VDC 'A' LPCI battery.

FitzPatrick has two trains of low pressure coolant injection (LPCI}. Each train consists of two pumps, piping, motor operated valves, and valve power supplies. The valves are powered by a 600 VAC power supply system which Is composed of two separate and independent power supplies which Includes a 419 VDC battery, 600 VAC emergency bus power supply, an inverter, a rectifier/charger, a transformer, and associated circuit breakers. The normal valve power supply is the 419 VDC, LPCI battery. A few weeks earlier, the battery had 1 of the 186 cells fail, resulting in the need for immediate replacement and unplanned entry Into the associated technical specification.

During Ms. England's review, she identified that the battery had an associated NRC finding in 2017 for an inadequate calculation of battery life. She noted that the work orders to replace the battery due to the reduced life were on Nominated by Eric Miller (FitzPatrick SRI) engineering hold. Ms. England requested additional information on battery performance testing. She developed a summary of the battery testing results, conducted interviews, and reviewed trending data. During her review, Ms. England identified that between 2013 and 2018, the 'A' LPCI battery experienced a greater than 10 percent change in capacity. Per IEEE-450 guidance and technical specifications, this met the definition of a degraded battery. As a result, the 5-year surveillance test of battery capacity should have been increased to annual in accordance with the Technical Specification Surveillance Requirement. The licensee performed a review and confirmed Ms. England's conoern. The licensee performed a site-wide stand down, underscoring the importance of documentation associated with work activities and the importance of ensuring compliance with technical specifications. Operators also entered Technical Specification Surveillance Requirement 3.0.3. Per this requirement, a risk assessment was performed, and the licensee completed a capacity test within the next few days. Ms. England's questioning-attitude, persistence and thoroughness were crucial to identifying this issue. Information gathering was difficult, but the previous development of the relationships with station personnel in different parts of the organization enabled Ms. England to obtain what she needed.

Ms. England showed outstanding teamwork and received support frorn branch peers and region-based battery experts to get deep into the details of battery performance and requirements. Inspector best practices: (a) Go the extra mile.

This may involve reviewing the system history (including maintenance, STs, mods, & operating experience), the licensee's CAP database, design basis calculations, vendor manuals, operating procedures & logs, and the UFSAR. Is there a Pl&R aspect to the issue? (b) Phone a friend. Remember that the regional staff, other residents, NRR OpE Clearinghouse, and the NRR staff are excellent resources to tap to help put your issue in perspective. (c) Follow up periodically to ensure corrective actions adequately addressed the problem. In addition, for identified deficiencies that are not promptly corrected, follow up periodically until the issues are resolved to ensure conditions do not degrade further.

Great catch, Jeni Remember:

Ensure proper form, fit, and function on plant mods.

APRIL 2023 INSPECTOR NEWSLETTER 14 F8R INTEAPl~b U&i OPIL¥ Answer to "What's wrong #1" The picture on page 5 shows a foreign material exclusion (FME) cover creatively constructed of duct tape. Pat Finney, SPE/DORS/RI, identified this while leading a biennial PI&R team inspection at Beaver Valley in February 2023. The FME cover in this application functions to protect the Ul turbine-driven AFW pump recirculation line chemical addition connection. The recirculation line is provided with a chemical feed tank for introducing chemicals to protect the carbon steel pumps, piping and primary plant demineralized water storage tank from the deleterious effects of dissolved oxygen in demineralized water. The licensee's FME procedure prohibited the use of tape as FME covers unless approved for the specific application (which it wasn't approved in this case). [KT: the licensee's procedure also included additional FME barrier expectations: FME barriers should be designated as such; be fire resistant/retardant; non-brittle, non-splitting, non-melting; shall not deteriorate or decompose over time; does not cause any chemical reaction; properly secured to prevent accidental displacement by wind, equipment movement, ventilation systems, or employees; tether internal FME devices externally to avoid inadvertent loss into the system during work activities; and consider using rigid covers on openings where falling objects could damage or penetrate the cover.] Inspector best practices: (a) There is no substitute for being there and seeing firsthand. (b) Maintain a questioning attitude. Make sure that your field observations align with the design basis and good engineering judgment. (c) When you know what "normal" looks like, then "abnormal" will jump right out at you. (d)

Ensure t hat you share your field observations with Operat ions and/or Engineering, as appropriate, in a timely manner. Do not analyze the condition for them or lower your standards. (e) Go the extra mile.

This may involve reviewing the design and licensing basis, industry operating experience, operating and maintenance procedures, and/or the CAP database. (f) Don't settle, you do not have to accept the licensee's first answer. If the licensee addressed some of your concerns, but did not resolve others, continue to push, in a professional manner, for a satisfactory answer. Great catch, Pat!

(Nominated by: Justin Fuller, Millstone SRI)

This quarter's Eagle Eyes Award goes out to Earl Bousquet, Millstone Resident Inspector. During a partial system walkdown inspection in the engineered safety features (ESF) building on January 11, 2023, Earl identified a through-wall flaw on the 3" diameter ASME Class 3 service water (SW) piping (see up close picture below). [KT: In the picture of the as-found condition on pggLJ, you may have noted the circled located above the leak location and the green color of the SW residue running down the pipe. The circle designates a routine inspection point (periodic UT thickness measurements as part of their GL 89-13 SW monitoring plan). The residue is green because the pipe is Monel, which has nickel and copper alloys.] This section of pipe is not isolable. This portion of the SW system supplies cooling water to the ESF building ventilation system which cools the following safety-related rooms: safety injection pump and quench spray pump areas, residual heat removal

APRIL 2023 INSPECTOR NEWSLETTER 15 T6R INT!RNAL US! ONLY pump and heat exchanger areas, containment recirculation pump and cooler areas, refueling water recirculation pump area, motor-driven auxiliary feedwater (AFW) pump areas, and turbine-driven AFW pump area. The licensee promptly entered structural integrity TRM action statement and evaluated the flaw in accordance ASME Code Case N-513. The licensee performed UT inspection of the weld, re-examined the through-wall flaw area (confirmed that the size was approximately 1.6" circumferential), and did not find any additional indications in the weld. The licensee determined that structural integrity was maintained and exited TRM 3.4.10 on January 14, 2023. The residents worked closely with a regional ASME Code guru, Nik Floyd (RI/DORS/EB1),

for technical support in reviewing the licensee's associated engineering technical evaluation and operability determination under the baseline inspection program. The resident inspectors also reached out to the NRC HQ PM (Rich Guzman) to keep him in the loop on the issue.

Inspector best practices: (a) There is no substitute for being there and seeing firsthand. What did the licensee overlook or fail to consider? (b) Maintain a questioning attitude. Make sure that your field observations align with the design basis and good engineering judgment. (c) When you know what "normal" looks like, then "abnormal" will jump right out at you. (d) Ensure that you share your field observations with Operations and/or Engineering, as appropriate, in a timely manner. Do not analyze the condition for them or lower your standards.

(e) Look at things from different angles, get down on the ground if necessary. However, make suire that you're fully aligned with the licensee's expectations before climbing (especially in the RCA). (f) Phone a friend.

Remember that the regional staff, other residents, NRR OpE Clearinghouse, and the NRR staff are excellent resources to tap to help put your issue in perspective. Great catch, Earl!

Up close look at the leak location. Approximately 9 feet above the floor below.

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APRIL 2023 I NSPECTOR NEWSLETTER 16 Answer to uwhat's wrong #3" The picture on page 12 shows Elise Eve, Senior Reactor Inspector RI/DORS/EBl, performing a containment inspection at Calvert Cliffs U2 during a refueling outage in February 2023. Elise identified an issue of concern associated with the floor grating contacting t he containment liner coating. Per design specifications, there should be a 1" gap between the grating and the containment coating for seismic concerns. Inspector best practices: (a) There is no substitute for being there and seeing firsthand. Those "out of the way" places and infrequently traveled spaces are ripe with opportunities (ensure that you follow the licensee's procedures and processes for access). Stay ready and keep your eyes & ears open for opportunities. (b) Maintain a questionin,g attitude. Make sure that your field observations align with the design basis and good engineering judgment. (c) When you know what

" normal" looks like, then " abnormal" will jump right out at you. (d) Look at things from different angles, get down on the ground if necessary. (e) The devil is in the details. Allot ample time for the walkdown and ensure that you load your inspection tool belt accordingly (flashlight, notebook, pen, safety gloves, drawings, system line-up). Great catch, Elise!

Chicago Pile interesting facts From an email by Kelly Korth, Sr. Reactor Technology Instructor, Technical Training Center On December 2, 1942, the world's first self-sustaining. controlled nuclear chain reaction took place paving the way for a variety of advancements in nuclear science.

The experiment took place at the University of Chicago's football stadium under the direction of Enrico Fermi, a Nobel Prize-winning scientist.

Chicago Pile-1 was the world's first nuclear reactor to go critical and fueled future research by the Energy Department's national laboratories to help develop early naval and nuclear reactors.

Fifteen years to this historic day, America's first full-scale atomic electric power plant went critical on December 2, 1957, as the nation began reaping the benefits of clean and reliable nuclear power.

Here are 10 intriguing facts you probably didn't know about the world's first controlled release of nuclear energy:

1. The experiment took place at 3:36 PM In a converted squash court at the University of Chicago's abandoned Stagg Field in Chicago, Illinois.

The Russians (Soviets at the time) int,erpreted the 1'squash courts" as a pumpkin field.

2. 49 scientists, led by Fermi, were present for the event. Leona Marshall was the lone female researcher.

Leona Woods (at the time) was not only the only female but was also the youngest researcher at 23 years old. She developed the BF3 detectors used to monitor the reaction. Her second husband, Willard Libby, developed radiocarbon dating methods for which he received the Noble Peace Prize in Chemistry, The team. Including Leona Woods. Only female and youngest member at 23 years old.

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