0CAN110903, Response to Request for Additional Information on the Response to Generic Letter 2008-01

Response to Request for Additional Information on the Response to Generic Letter 2008-01

ML093230833
Person / Time
Site:	Arkansas Nuclear   (DPR-051, NPF-006)
Issue date:	11/18/2009
From:	Walsh K Entergy Operations
To:	Document Control Desk, Office of Nuclear Material Safety and Safeguards, Office of Nuclear Reactor Regulation
References
0CAN110903, GL-08-001
Download: ML093230833 (11)

Text

0CAN110903 November 18, 2009 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555

SUBJECT:

Response to Request for Additional Information On the Response To Generic Letter 2008-01 Arkansas Nuclear One, Units 1 and 2 Docket Nos. 50-313, 50-368, and 72-13 (ISFSI)

License Nos. DPR-51 and NPF-6

REFERENCES:

1. Generic Letter 2008-01, dated January 11, 2008, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (0CNA010801)

2. Entergy letter to the NRC, dated October 14, 2008, Nine-Month response to NRC Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (0CAN100801)

3. Entergy letter to the NRC, dated March 16, 2009, Post-Outage Supplemental Response to NRC Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (1CAN030905)

4. Email from Kaly Kalyanam (NRC) to Robert W. Clark (Entergy), dated October 19, 2009, Request for Additional Information - GL 2008-01

Dear Sir or Madam:

The U. S. Nuclear Regulatory Commission (NRC) issued Generic Letter (GL) 2008-01 (Reference 1) to request that each licensee evaluate the licensing basis, design, testing, and corrective action programs for the Emergency Core Cooling Systems (ECCS), Decay Heat Removal (DHR) system or Shutdown Cooling (SDC) system, and Containment Spray system, to ensure that gas accumulation is maintained less than the amount that challenges operability of these systems, and that appropriate action is taken when conditions adverse to quality are identified.

Entergy Operations, Inc.

1448 S.R. 333 Russellville, AR 72802 Tel 479-858-3110 Kevin T. Walsh Vice President, Operations Arkansas Nuclear One

0CAN110903 Page 2 of 3 By References 2 and 3, Entergy Operations, Inc. (Entergy) provided the nine-month response to the GL for Arkansas Nuclear One, Units 1 and 2 (ANO-1 and 2) and the post-outage supplemental response for ANO-1, respectively.

On the basis of the information provided, the NRC Staff has concluded that additional information is required to determine that Entergy has acceptably demonstrated that the subject systems are in compliance with the current licensing and design bases and applicable regulatory requirements, and that suitable design, operational, and testing control measures are in place for maintaining this compliance as stated in the GL for ANO-1 and 2. This request was provided via Reference 4.

It should be noted that the post-outage supplemental response for ANO-2 has not been transmitted to the NRC. This submittal is currently being prepared.

The individual requests for information and the ANO response are provided in Attachment 1.

This letter contains no new commitments.

If you have any questions or require additional information, please contact David Bice at 479-858-5338.

I declare under penalty of perjury that the foregoing is true and correct. Executed on November 18, 2009.

Sincerely, Original signed by Kevin T. Walsh KTW/rwc

Attachment:

Response to Request for Additional Information on the Response to GL 2008-01

0CAN110903 Page 3 of 3 cc:

Mr. Elmo E. Collins Regional Administrator U. S. Nuclear Regulatory Commission Region IV 612 E. Lamar Blvd., Suite 400 Arlington, TX 76011-4125 NRC Senior Resident Inspector Arkansas Nuclear One P. O. Box 310 London, AR 72847 U. S. Nuclear Regulatory Commission Attn: Mr. Kaly Kalyanam MS O-8 B1 One White Flint North 11555 Rockville Pike Rockville, MD 20852 Mr. Bernard R. Bevill Arkansas Department of Health Radiation Control Section 4815 West Markham Street Slot #30 Little Rock, AR 72205

Attachment to 0CAN110903 Response to Request for Additional Information On The Response to GL 2008-01

Attachment to 0CAN110903 Page 1 of 7 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION ON THE RESPONSE TO GL 2008-01 Guidance on Nuclear Regulatory Commission (NRC) Staff expectations is provided in Reference 1, which is generally consistent with Nuclear Energy Institute (NEI) guidance provided to the industry in Reference 2, as clarified in later NEI communications. The NRC Staff recommends that the licensee consult Reference 1 when responding to the follow Request for Additional Information.

Item specifically applicable to Arkansas Nuclear One (ANO) Unit 1:

1. Discuss how core flood (CF) system venting procedures assure operability when the system is similarly voided under design basis conditions.

Maintenance evolutions requiring the draining of the CF system piping are rare.

Normal operating procedures ensure the piping is not voided during refueling outages (see 1.a below). The likelihood of significant gas accumulation in the CF system piping is small due to system design / configuration, as verified by the ultrasonic testing (UT) performed during the fall of 2008 refueling outage (1R21). The system is dynamically flushed each refueling outage during CF tank (CFT) discharge check valve stroke tests (i.e., normal surveillance testing). The small amount of gas which could be trapped in the horizontal piping of the CF system due to slope variations and system component design is not of concern with respect to CF system operability or with post-Loss of Coolant Accident (LOCA) core cooling, when compared to the assumed volume of nitrogen which could enter the Reactor Coolant System (RCS) following a LOCA.

During large and intermediate break LOCAs where the CFTs discharge to the reactor vessel, the nitrogen cover may discharge almost all the water from the system resulting in a nearly empty system. This post-LOCA configuration is expected per the design basis. Once voided during a design basis accident, the system is not required to be filled and pressurized again for re-use to further mitigate the accident. See 1.a and 1.b below for additional information related to the aforementioned discussion.

For instance:

a. Are the CF tanks assumed (in applicable LOCA analyses) to empty under 60 - 70 psi pressure differential conditions? Please comment on any differences.

The 60 - 70 psig CFT pressure utilized during refueling outages to test the discharge check valves ensures enough flow to properly stroke the discharge check valves, but also ensures that water will remain in the CFTs following this test such that nitrogen will not enter any of the CF system piping (and therefore require venting). The CFT discharge during refueling outage check valve testing typically leaves one to three feet of water in the CFTs.

Attachment to 0CAN110903 Page 2 of 7 No voids in the CF system piping were found during the 1R21 (Fall 2008) refueling outage, thus indicating that the discharge tests conducted with only 60 - 70 psig tank pressure are sufficient to ensure no voids exist in the CF system piping.

As noted above, the check valve testing during refueling outages does not void any CF system piping. However, during LOCA injection, nitrogen will likely void the CF system piping and enter the RCS during blow down of the tanks. The reactor core and RCS has been evaluated for the injection of 2400 cubic feet of nitrogen following post-LOCA CFT injection. The nitrogen injected in the core following post-LOCA injection will likely exit the RCS at the break location. High point vents are provided on the reactor vessel head and both hot legs in the event venting of gasses in the RCS is required following a LOCA.

b. Does the LOCA model assume CF tank discharge characteristics that are as likely to sweep away voiding as the current venting procedure?

During each refueling outage, full stroke tests of CFT outlet check valves CF-1A/B and DH-14A/B are performed. The full stroke tests of these check valves are performed by discharging the CFTs to the refueling canal via the reactor vessel. Approximately 10 feet of level in the CFTs are injected into the reactor vessel with 60 - 70 psig of pressurized nitrogen cover in the CFTs. The CF piping is not voided during this test. The maximum CFT outlet flow though the 14 inch CF piping in the A train was found to be approximately 11,000 gallons per minute (gpm) during 1R10 (Spring of 1992) check valve stroke testing. Maximum flow rates in excess of 7000 gpm for each train have been calculated with an assumed nitrogen pressure of 60 psig in each tank.

The CF piping is generally 14 schedule 140 pipe. At 7000 gpm, the fluid velocity is approximately 21.6 feet/second and the calculated Froude number (NFR) is approximately 3.89 for 14 schedule 140 pipe. In consideration of industry information that indicates a Froude number in excess of 1.0 will result in void evacuation in system piping, the noted CF piping Froude numbers are considered more than sufficient to flush any gas voids from the CF system piping during the check valve testing conducted during refueling outages.

As discussed previously, the reactor core has been evaluated for the injection of 2400 cubic feet of nitrogen following post-LOCA CFT injection which bounds any minor gas voids in the system piping which could be injected into the core during CFT injection.

Attachment to 0CAN110903 Page 3 of 7

2. Discuss whether ultrasonic (UT) and/or venting is re-performed at locations where gas may accumulate during venting at other locations to verify gas was removed during venting and ensure gas was not transported to a high point that was previously found to be void free. If such activity is deemed unnecessary at ANO-1, please briefly explain why.

The ANO-1 overall strategy during UT verifications was to wait for Operations to complete their normal/routine fill and venting activities and then check to determine if the system is water solid.

In the case of CFT lines, the water level is typically maintained above the primary supply lines to ensure that no gas voiding occurs. However in cases where drain downs are required for maintenance activities such as Alloy 600 repairs, once the RCS is returned to an intact configuration, UT was utilized to verify the CFT outlet lines remained water solid. Periodic CFT blow downs (one of two CFTs per outage) ensure the CFT outlet lines are water solid based on the blow down flow rates.

For Decay Heat / Low Pressure Injection (DH/LPI) lines, the Fall of 2008 refueling outage (1R21) Alloy 600 repairs required a portion of each trains injection line to be drained. Pipe elevation measurements were performed to verify locations of high spots. Once these lines were refilled and DH flow established, these Reactor Building (RB) high spots were tested with UT equipment to verify water solid conditions and no additional venting was performed. Preliminary analysis of each DH/LPI and crossover lines flow indicated there was sufficient flow to flush any gas voids to the reactor vessel, which was open to the atmosphere. UT confirmed the preliminary analysis.

For the High Pressure Injection (HPI) lines, pipe elevation measurements were performed to verify locations of high spots. Following completion of HPI system fill and venting, UT was performed at selected system high spots in the RB to confirm the lines were water solid and no additional venting was performed. Preliminary analysis also demonstrated that typical system full flow testing readily flushes any gas voids to the reactor vessel.

Following ANO-1 return to power operation, additional UT was performed at selected high spots in the Auxiliary Building for the HPI and DH/LPI systems and no gas voids were identified. Additional UT has confirmed that no new gas voiding is occurring in the HPI and LPI systems.

Attachment to 0CAN110903 Page 4 of 7 Items specifically applicable to ANO-2:

3. Explain why Safety Injection Tanks (the staff assumes that SIT stands for Safety Injection Tank) are not identified as within the scope of the GL 2008-01 review.

The Safety Injection Tanks (SITs) are considered as part of the Low Pressure Safety Injection (LPSI) System. The ANO-2 Emergency Core Cooling System (ECCS) utilizes four injection paths with each injection path consisting of (1) Red Train (electrical) High Pressure Safety Injection (HPSI) line, (1) Green Train (electrical) HPSI line, (1) LPSI line and (1) SIT. The (2) HPSI lines, (1) LPSI line and (1) SIT combine (via check valves and Motor Operated Valves (MOVs)) to form a common ECCS injection line.

For analysis purposes and for purposes of this response, the SITs are considered part of the LPSI System.

4. Provide additional details regarding the statement, ANO-2 procedures provide assurance that the volume of gas in the pump suction piping for the subject systems is limited such that the pump gas ingestion is within the above established interim criteria (Reference 3). Please summarize the actions required by these procedures, focusing on those aspects assuring that gas ingestion is within the criteria.

ANO-2 currently maintains a zero acceptable void limit criteria for design basis consideration. If a void is identified during periodic void checks or other plant activities, Condition Reports are issued and operability is established based on the size and location of the void. Operability up to and including current industry guidance may be utilized; however, to date voids that have been identified have been small (< 0.2 ft3) and have been located on the pump discharge lines. The HPSI System and LPSI System operating procedures have requirements to perform UT on affected sections of pipe as part of the return to service requirements after maintenance has been performed which breaches the systems pressure boundary. This assures that the system piping remains water solid prior to return to service.

In addition, monitoring of the system utilizing UT equipment is conducted on a quarterly basis as part of a preventative maintenance activity. UT is performed on the HPSI pump discharge and the HPSI and LPSI injection isolation MOVs and injection line high points to ensure that no voids have formed in the system.

Attachment to 0CAN110903 Page 5 of 7 Items applicable to both units:

5. Describe how gas void volumes have been or would be determined for comparison to the acceptance criteria discussed in Attachments 1 and 2 to Reference 1. With regard to ANO-1, please ensure that the response addresses voiding in the LPI lines, particularly upstream of DH-13A/B, DH-17, DH-18; NaOH piping, and any voiding assessment for the CF tanks. With regard to ANO-2, please ensure that the response addresses qualitative determinations, i.e.,

please clarify statements such as, two minor voids were identified in the CSS bypass lines (Reference 3).

ANO-1 ANO-1 utilizes the UT analysis of GL 2008-01 affected piping to identify potential gas voids in ECCS and additional systems. When a gas void is found, its size is determined via additional UT of accessible lines or conservatively estimated based on available information. The Reference 3, Attachment 1, Question 2 interim criteria were initially to be used for pump suction voids as operability limits. Future gas void size limits will be based on internal analysis and/or generic industry information based on actual or modeled pump/piping testing on a case by case basis. However, the ANO-1 goal is 0% gas voiding by volume on all ECCS and other critical pumps. Based on the 1R21 pipe elevations and follow-up UT, there were no gas voids identified at selected locations on the DH/LPI, HPI, and CF systems.

Piping upstream of DH-13A/B, DH-17, and DH-18 is subject to gas void formation due to a reduction in pressure of approximately 600 psid across these valves. It has been determined for these specific lines an allowed void size of 0.175 cubic feet in each of these lines will maintain these lines ASME code qualified. So that Operations and Engineering can quickly assess gas voiding concerns, an analysis was performed to determine the amount of time it takes for this void size to force water out of 3/8 OD tubing. The results of this analysis have been added to the DH operating procedure and indicate that depressurization times less than approximately 105 seconds ensures acceptable gas void conditions at a starting pressure of 60 psi. Currently, typical depressurization times are less than 20 seconds, as documented in the Unit 1 station log.

The NaOH piping configuration consists of localized high spots in the horizontal portion of the piping just downstream of the NaOH tank at the location of train separation. This area of piping includes the injection MOVs, CV-1616 and CV-1617, the NaOH tank outlet valve, CA-49, and the piping tie-ins to the Auxiliary Building Drain (ABD) system and Condensate system (CS). Due to Chemistry concerns regarding the transportation of NaOH into the ECCS suction lines, filling the NaOH lines is accomplished via small (1) condensate connections located downstream of CV-1616 and CV-1617 and at physical elevations lower than CV-1616 and CV-1617. The filling method is best described as a flushing evolution - aligning Condensate downstream of CV-1616 and CV-1617 allowing the lines to fill and then be flushed to the small (1) ABD connection upstream of the injection MOVs. Since these 1 ABD lines are attached into the 4 process lines at the horizontal joint, approximately 30% of the process pipe cannot be vented as there are no vent valves in this portion of the piping. A combination of the

Attachment to 0CAN110903 Page 6 of 7 localized high spots near the injection MOVs, the 1 to 4 horizontal connections, and insufficient condensate flow utilized for flushing, results in the inability to remove the noted gas voids. ANO-1 is currently evaluating the installation of vents in this area.

This area is monitored with UT equipment every six months. To date the size of the voids (< 0.003 cubic feet [< 4 cubic inches] around NaOH tank discharge valve CV-1617 and < 0.3 cubic inches downstream from NaOH tank discharge valve CV-1616) have not grown. It is noted that the operability established for the original void identification bounds the current void size.

ANO-2 In general ANO utilizes UT equipment to identify and characterize voids in system piping. For vertical piping water level can be determined by direct utilization of the probe. For horizontal piping that is partially filled the UT probe can be used at either the top or the bottom of the pipe to determine the void end points and then along the perimeter of the pipe at the voids largest point to determine the water level within the pipe. Given this information and system pressure the void size can be determined.

When the bare piping surface is not accessible or piping conditions are such that the UT probe is ineffective, alternate quantification strategies may be used or conservative estimate made for the void size.

Regarding the specific issue concerning the CSS bypass line, from the Condition Report

Description:

A small gas void was discovered in the 3 inch bypass line around the containment spray header isolation valve 2CV-5612-1. The volume of the void was characterized by UT data and determined to be 0.89 gallons. This condition was discovered as part of the GL-2008-01 "Gas Accumulation" generic letter data collection walk down. The 10 inch spray header was verified full with UT data. This CR is issued to document the small void.

The 0.89 gallon size equates to a void size of 0.12 ft3. Additionally the spray bypass lines are normally closed and remain closed in an accident.

6. Provide a brief discussion of any training that is planned in response to GL 2008-01.

ANO is an active participant in the NEI Gas Accumulation Team, which is currently coordinating with the Institute of Nuclear Power Operations (INPO) in the development of generic training modules for gas accumulation and management. These training modules target the Engineering, Operations and Maintenance disciplines. When these training modules are completed and become available to the industry, ANO will evaluate them for applicability to ANO, and may implement a version tailored to meet station needs. Pending release of the INPO products, the schedule for such planned training has not yet been determined.

Attachment to 0CAN110903 Page 7 of 7 In addition to active participation in industry training activities, ANO has provided training to the Unit 1 and 2 Operations personnel during scheduled cycle training.

References to this GL have been added to the initial lesson plans for the applicable systems. Additionally, INPO SOER 97-1 and the more recent SER 2-05 have been added as recurring training items to the ANO licensed operator requalification program and have also been added to related initial system training materials. Electrical and Mechanical Maintenance personnel have received training on this subject as well.

Engineering Support Personnel training material has been developed and provided to a limited number of engineering personnel while waiting on the conclusion of the industry training efforts.

REFERENCES

1. Ruland, William H., USNRC, letter to Riley, James H., Nuclear Energy Institute, Preliminary Assessment of Responses to Generic Letter 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems, and Future NRC Staff Review Plans, May 28, 2009. ADAMS Accession ML091390637.

2. Riley, James H., Nuclear Energy Institute, letter to Administrative Points of Contact Generic Letter (GL) 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems Evaluation and 3 Month Response Template, Enclosure 2, Generic Letter 2008-01 Response Guidance, March 20, 2008.

3. Mitchell, Timothy G., Entergy Operations, letter to USNRC, Nine-Month Response to NRC Generic Letter 2008-01 Dockets 50-313 and 50-368, October 14, 2008.

ADAMS Accession ML082900147.