ML14174A832

EA-14-008_Arkansas Nuclear One, Units 1 and 2 - Final Significance Determination of Two Yellow Findings and Notice of Violation; NRC Inspection Report 05000313/2014008 and 05000368/2014008

ML14174A832
Person / Time
Site:	Arkansas Nuclear
Issue date:	06/23/2014
From:	Dapas M NRC Region 4
To:	Jeremy G. Browning Entergy Operations
References
EA-14-008 IR-14-008
Download: ML14174A832 (10)

See also: IR 05000313/2014008

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E LAMAR BLVD

ARLINGTON, TX 76011-4511

June 23, 2014

EA-14-008

Jeremy Browning, Site Vice President

Entergy Operations, Inc.

Arkansas Nuclear One

1448 SR 333

Russellville, AR 72802-0967

SUBJECT: ARKANSAS NUCLEAR ONE, UNITS 1 AND 2 - FINAL SIGNIFICANCE

DETERMINATION OF TWO YELLOW FINDINGS AND NOTICE OF VIOLATION;

NRC INSPECTION REPORT 05000313/2014008 AND 05000368/2014008

Dear Mr. Browning:

This letter provides you the final significance determination of the preliminary Red and Yellow

findings identified in NRC Inspection Report 05000313/2013012; 05000368/2013012

(ML14083A409), dated March 24, 2014. A detailed description of the findings is contained in

Section 4OA3.9 of that report. The findings are associated with the March 31, 2013, Unit 1

stator drop that affected safety-related equipment on both units.

At your request, a Regulatory Conference was held on May 1, 2014, to further discuss your

views on these findings. A copy of your presentation provided at this meeting is attached to the

summary of the Regulatory Conference (ML14128A512), dated May 9, 2014. In your

presentation on the risk significance of the event related to Unit 1, you described four recovery

actions that plant personnel could have implemented to establish and maintain cooling to the

reactor core in the event that the emergency diesel generators were not able to supply power to

the 4160V electrical buses. Three of these methods involved restoring power to 4160V safety-

related electrical buses from other sources. The fourth recovery method involved providing

temporary 480V ac power to a borated water recirculating pump, and establishing a source of

water to the reactor from the borated water storage tank.

Based on your staff's evaluation of the probability of success of the four recovery actions, and

the amount of time that existed to restore cooling to the core, your staff concluded that the

change in core damage probability was 4.8 x 10-6. As a result, you concluded that the

inspection finding should be characterized as White, low-to-moderate safety significance.

J. Browning -2-

In your presentation on the risk significance of the event related to Unit 2, you described three

procedurally directed recovery strategies that plant personnel could have implemented to

restore electrical power in the event that power was lost to vital electrical buses. These

strategies involved supplying power from the Startup 2 transformer, or the alternate ac diesel

generator to electrical buses, and cross connecting the vital 4160V buses to supply power to

equipment. Based on your staff's evaluation of the probability of success of these three

procedurally directed recovery strategies, your staff concluded that the change in conditional

core damage probability was 1.8 x 10-6. As a result, you concluded that this inspection finding

should also be characterized as White, low-to-moderate safety significance.

After considering the information developed during the inspection and the information you

provided at the Regulatory Conference, we have concluded that the risk significance of each

finding is appropriately characterized as Yellow, substantial safety significance, for both Units 1

and 2. Our evaluation of the risk significance of each inspection finding is provided in

Enclosure 2 of this letter.

You have 30 calendar days from the date of this letter to appeal the staffs determination of

significance for the identified Yellow findings. Such appeals will be considered to have merit

only if they meet the criteria given in Inspection Manual Chapter 0609, Significance

Determination Process, Attachment 2. An appeal must be sent in writing to the Regional

Administrator, Region IV, 1600 E. Lamar Blvd., Arlington, TX 76011-4511.

The NRC has also determined that the failure to follow procedures to ensure that a temporary

lift assembly was designed to support the projected load and to perform a 125 percent load test

for the projected load is a violation of Title 10 of the Code of Federal Regulations (CFR) Part 50,

Appendix B, Criteria V, Instructions, Procedures and Drawings, as cited in the attached Notice

of Violation. In accordance with the NRCs Enforcement Policy, the Notice is considered

escalated enforcement action because it is associated with Yellow findings for Units 1 and 2.

You are required to respond to this letter and should follow the instructions specified in the

enclosed Notice when preparing your response. If you have additional information that you

believe the NRC should consider, you may provide it in your response to the Notice. The NRCs

review of your response to the Notice will also determine whether further enforcement action is

necessary to ensure compliance with regulatory requirements.

Because plant performance at the Arkansas Nuclear One facility has been determined to be

beyond the "Licensee Response Column" of the NRCs Reactor Oversight Process Action

Matrix, as the result of Units 1 and 2 Yellow significance findings, the NRC will use the Action

Matrix to determine the most appropriate NRC response to the findings' significance. We will

notify you, by separate correspondence, of that determination.

J. Browning -3-

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice and Procedure," a copy of

this letter, its enclosures, and your response will be made available electronically for public

inspection in the NRCs Public Document Room or from the NRCs Agencywide Documents

Access and Management System (ADAMS), accessible from the NRC website at

http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not

include any personal privacy, proprietary, or safeguards information so that it can be made

available to the Public without redaction.

Sincerely,

/RA/

Marc L. Dapas

Regional Administrator

Dockets: 50-313; 50-368

Licenses: DPR-51; NPF-6

Enclosures:

1. Notice of Violation

2. Final Significance Determination

SUNSI Review ADAMS Publicly Available Non-Sensitive Keyword:

By: Yes No Non-Publicly Available Sensitive

OFFICE SPE:PBE SRA:TSB SRRA:NRR/ SES:ACES C:ACES RC:ORA C:PBE

DRA/APHB

NAME MBloodgood DLoveless JMitman RBrowder VCampbell KFuller GWerner

SIGNATURE /RA/ jm for via email via email /RA/ /RA/ /RA/ /RA/ TRF for

DATE 06/4/14 06/12/14 06/12/14 06/2/14 06/4/14 06/3/14 06/12/14

OFFICE TL:NRR/ DD:DRP D:DRP OE NRR RA

DRA/APHB

NAME JCircle TPruett KKennedy LCasey CSanders MDapas

SIGNATURE via email /RA/ /RA/ via email via email /RA/

DATE 06/12/14 06/12/14 06/13/14 06/13/14 06/18/14 6/23/14

Letter to Jeremy Browning from Marc L. Dapas dated June 23, 2014

SUBJECT: ARKANSAS NUCLEAR ONE, UNITS 1 AND 2 - FINAL SIGNIFICANCE

DETERMINATION OF TWO YELLOW FINDINGS AND NOTICE OF VIOLATION;

NRC INSPECTION REPORT 05000313/2014008 AND 05000368/2014008

Distribution

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RidsRgn2MailCenter Resource; RidsRgn3MailCenter Resource; NRREnforcement.Resource;

RidsNrrDirsEnforcement Resource;

Marc.Dapas@nrc.gov; Karla.Fuller@nrc.gov; Roy.Zimmerman@nrc.gov;

Anton.Vegel@nrc.gov; Bill.Maier@nrc.gov; Nick.Hilton@nrc.gov;

Kriss.Kennedy@nrc.gov; Jeff.Clark@nrc.gov ; John.Wray@nrc.gov;

Troy.Pruett@nrc.gov; Geoffrey.Miller@nrc.gov; David.Furst@nrc.gov;

Vivian.Campbell@nrc.gov; Rachel.Browder@nrc.gov; Gerald.Gulla@nrc.gov;

Christi.Maier@nrc.gov; Victor.Dricks@nrc.gov; Lauren.Casey@nrc.gov;

Marisa.Herrera@nrc.gov; Lara.Uselding@nrc.gov; Robert.Carpenter@nrc.gov;

R4Enforcement; Jeffrey.Clark@nrc.gov; Robert.Fretz@nrc.gov;

Brian.Tindell@nrc.gov; Matthew.Young@nrc.gov; Carleen.Sanders@nrc.gov;

Abin.Fairbanks@nrc.gov; Greg.Werner@nrc.gov; Michael.Bloodgood@nrc.gov;

Joseph.Nick@nrc.gov; Jim.Melfi@nrc.gov; Gloria.Hatfield@nrc.gov;

Peter.Bamford@nrc.gov; Lorretta.Williams@nrc.gov; Jenny.Weil@nrc.gov;

NOTICE OF VIOLATION

Entergy Operations, Inc. Dockets: 05-313,05-368

Arkansas Nuclear One, Units 1 and 2 Licenses: DRP-51, NPF-6

EA-14-008

During an NRC inspection conducted between July 22, 2013, and February 10, 2014, a violation

of NRC requirements was identified. In accordance with the NRCs Enforcement Policy, the

violation is listed below:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings,

states, in part, that activities affecting quality shall be prescribed by documented

instructions, procedures, or drawings of a type appropriate to the circumstances and

shall be accomplished in accordance with these instructions, procedures, or drawings.

Quality Procedure EN-MA-119, Material Handling Program, Section 5.2[7], Temporary

Hoisting Assemblies, Step (a) states, in part, that vendor supplied temporary overhead

cranes or supports, winch-driven hoisting or swing equipment, and other assemblies are

required to be designed or approved by engineering support personnel. The design is

required to be supported by detailed drawings, specifications, evaluations, and/or

certifications.

Quality Procedure EN-MA-119, Material Handling Program, Section 5.2[7], Temporary

Hoisting Assemblies, Step (b) states, in part, that the assembly shall be designed for at

least 125 percent of the projected hook load and should be load tested and held for at

least 5 minutes at 125 percent of the actual load rating before initial use. The assembly

shall be load tested in all configurations for which it will be used.

Contrary to the above, on March 31, 2013, the licensee did not accomplish the Unit 1

main turbine generator stator lift and move, an activity affecting quality, as prescribed by

documented instructions and procedures. Specifically:

A. The licensee approved a design for the temporary hoisting assembly that was not

supported by detailed drawings, specifications, evaluations, and/or certifications. The

licensee failed to identify the load deficiencies in vendor Calculation 27619-C1, "Heavy

Lift Gantry Calculation," and the incorrectly sized component in the north tower

structure of the temporary hoisting assembly. In addition, the temporary hoisting

assembly was not designed for at least 125 percent of the projected hook load.

B. The licensee failed to perform a load test in all configurations for which the

temporary hoisting assembly would be used.

As a result, on March 31, 2013, while lifting and transferring the Unit 1 main turbine

generator stator, the temporary overhead crane collapsed causing the 525-ton stator to

fall on and extensively damage portions of the plant, affecting safety-related equipment.

This violation is associated with a Yellow (Unit 1) and a Yellow (Unit 2) significance

determination finding.

Enclosure 1

Pursuant to the provisions of 10 CFR 2.201, Entergy Operations, Inc., is hereby required to

submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001 with a copy to the Regional

Administrator, Region IV, and a copy to the NRC resident inspector at the facility that is the

subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation

(Notice). This reply should be clearly marked as a "Reply to a Notice of Violation; EA-14-008"

and should include for each violation: (1) the reason for the violation, or, if contested, the basis

for disputing the violation or severity level; (2) the corrective steps that have been taken and the

results achieved; (3) the corrective steps that will be taken; and (4) the date when full

compliance will be achieved.

Your response may reference or include previous docketed correspondence, if the

correspondence adequately addresses the required response. If an adequate reply is not

received within the time specified in this Notice, an order or a Demand for Information may be

issued as to why the license should not be modified, suspended, or revoked, or why such other

action as may be proper should not be taken. Where good cause is shown, consideration will

be given to extending the response time.

If you contest this enforcement action, you should also provide a copy of your response, with

the basis for your denial, to the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington, DC 20555-0001.

Because your response will be made available electronically for public inspection in the NRCs

Public Document Room or from the NRCs document system (ADAMS), accessible from the

NRC website at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should not

include any personal privacy, proprietary, or safeguards information so that it can be made

available to the public without redaction. If personal privacy or proprietary information is

necessary to provide an acceptable response, then please provide a bracketed copy of your

response that identifies the information that should be protected and a redacted copy of your

response that deletes such information.

If you request withholding of such material, you must specifically identify the portions of your

response that you seek to have withheld and provide in detail the bases for your claim of

withholding (e.g., explain why the disclosure of information will create an unwarranted invasion

of personal privacy or provide the information required by 10 CFR 2.390(b) to support a request

for withholding confidential commercial or financial information). If safeguards information is

necessary to provide an acceptable response, please provide the level of protection described

in 10 CFR 73.21.

Dated this 23rd day of June 2014

2

Arkansas Nuclear One Dropped Stator

Final Significance Determination

During the regulatory conference held on May 1, 2014, your staff described their assessment of

the significance of the finding for each unit. Specifically, your staff discussed differences for

Units 1 and 2 that existed between the NRCs preliminary significance determination and

Arkansas Nuclear Ones risk assessment. The differences for each unit were evaluated and are

discussed below.

Unit 1

1. Your staff specified a time to boil of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and a time to core uncovery of 115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br />

versus NRC values of 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> and 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />, respectively.

We determined that the change in the time to boil had minimal impact on the risk evaluation.

Using the 115 hours0.00133 days <br />0.0319 hours <br />1.901455e-4 weeks <br />4.37575e-5 months <br /> for time to core uncovery, the total conditional core damage probability

was reduced from 3.8 x 10-4 to 2.6 x 10-4.

2. Your staff described three success paths to recover offsite power, and that during the actual

event, Entergy Operations, Inc., personnel were successful in establishing a temporary

electrical connection between the switchyard and the 4160V safety buses within 4.4 days of

the event initiation, contrary to the NRC using 6 days in our preliminary risk analysis. As

part of their analysis, your staff developed an estimated probability of successful recovery of

97 percent.

After reviewing the information that your staff provided during the regulatory conference, we

agree that the recovery of offsite power was feasible within the time to core uncovery. It is

important to note that there was an extended period of time before core uncovery would

occur and this was the primary reason that we determined you could recover offsite power

with a high chance of success. Accordingly, we determined that a 90 percent probability of

success for recovering electrical power best reflects the broader spectrum of possible

scenarios that could be present during a station blackout where the environmental

conditions would be degraded; fewer personnel would be available to respond based on the

escalation of emergency action level classification; and a higher level of stress would be

imposed on those planning, implementing, testing, and approving the new and non-

procedural modifications for recovering offsite power. Using this high probability of success,

we determined that the risk estimate should be reduced to 6 x 10-5.

3. Your staff also described a success path to restore power to the borated water recirculation

pump for reactor coolant system makeup.

During the conference, your staff indicated that temporary 480V power could be supplied

to the borated water recirculation pump and water could be supplied to the reactor from

the borated water storage tank; however, your staff discussed that restoration of the

4160V buses would be the priority because of the varied equipment that could be powered

and used to keep the core covered. Although at the regulatory conference, your staff

presented power restoration to the borated water recirculation pump as a potential success

path to establishing makeup water to the reactor, they indicated that this option was not

evaluated, during the event. Similar to the three success paths for recovering offsite power

Enclosure 2

referenced above, temporary power cables would have to be run from an offsite power

source into the plant in order to energize the 480V bus associated with the borated water

recirculation pump. This evolution would need to be conducted during challenging adverse

plant conditions associated with flood water accumulation from a ruptured fire protection

header, as well as reduced lighting and elevated room temperatures resulting from a station

blackout. These adverse plant conditions, in our view, would affect the probability of

success in pursuing this path to provide for reactor coolant system makeup, and as such,

the appropriate probability of success is 90 percent. Consequently, we determined that this

was affectively another method of restoring offsite power, so no additional credit was

warranted.

In summary, we reduced our Unit 1 preliminary risk assessment to 6 x 10-5 (Yellow) because we

determined a high likelihood of success (90 percent) existed for recovering electrical power

based on the time available to complete those actions prior to core uncovery.

Unit 2

Your staff stated during the regulatory conference, that there were three methods of restoring

vital power to risk-important equipment that were not credited by the NRC in the preliminary

significance determination:

1. Your staff indicated that Switchgear 2A2, while not powered throughout the event, was

always capable of being restored via the Startup 2 transformer. Additionally, your staff

stated that changes in your probabilistic risk model of record were made to account for

operator actions specifically related to the load shed breakers on 4160V Bus 2A2. This

change added a non-recovery probability for operators to manually manipulate the breakers

should they fail to operate automatically.

We reviewed the NRC's standardized plant analysis risk model and determined that

operators aligning Bus 2A2 to offsite power (Startup 2 transformer) and the human error

probability of operators failing to align 4160V Bus 2A2 to offsite power under conditions

following the stator drop were already incorporated into our preliminary significance

determination. The environmental conditions of debris and water surrounding the

switchgear area after the load drop event and the increased stress level of operations

personnel could complicate recovery. Taking these factors into account would increase the

probability of non-recovery of 4160V Bus 2A2. Therefore, we determined that no additional

reduction of the human error probability for recovery of 4160V Bus 2A2 involving manual

action to manipulate the associated load shed breakers, relative to the human error

probability used in our preliminary significance determination, was warranted.

2. Your staff indicated that the alternate ac diesel generator and the 4160V Bus 2A9 supply to

Unit 2 buses were damaged, but available throughout the event. Your staff also stated that

Unit 2 control room operators would have used the alternate ac diesel generator in the event

of a station blackout because they were unaware of any damage to 4160V Bus 2A9.

We determined that plant staff were aware of the potential damage to 4160V Bus 2A1,

located next to Bus 2A9, and operators at both units would have been notified of damage to

4160V Bus 2A9, in accordance with site procedures. This is based on the fact that Unit 1

operators were aware of the damage to alternate ac diesel generator output electrical

connections to Bus 2A9 for Unit 1, and that Procedure 2104.037, Alternate AC Diesel

2

Generator Operations, contains a number of steps for the Unit 2 operators to notify and

coordinate with the Unit 1 operators before starting and loading the alternate ac diesel

generator. We believe that the Unit 1 operators would have informed the Unit 2 operators of

the damage to electrical buses. We further concluded that it was reasonable to assume that

the Unit 2 operators would have requested an investigation of the bus condition before using

the alternate ac diesel generator.

We determined that investigation, repair, and/or testing of the bus condition by maintenance

personnel would have taken longer than the time to core damage following a postulated

station blackout with failure of the turbine-driven emergency feedwater pump. Therefore, no

recovery credit was applied to short (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) core damage sequences. However, we did

determine that applying recovery credit for 8-hour sequences would reduce the conditional

core damage probability to 1.2 X 10-5 (Yellow).

3. Your staff indicated that the ability to cross-tie vital 4160V Buses 2A3 and 2A4 was available

to the operators and not credited in the NRC's preliminary significance determination.

We determined that the ability to cross-tie the 4160V vital buses would not significantly

impact the final results. In the dominant accident sequence, having one energized vital bus

was already considered "electrical success," and any additional electrical system recovery

to power the opposite vital bus would have a minimal impact on the overall risk assessment

result.

In summary, we concluded that our Unit 2 preliminary risk assessment of 2.8 x 10-5 (Yellow)

appropriately characterized the risk significance of the finding and that the information presented

at the regulatory conference did not appreciably change the final risk determination.

3