IR 05000416/2006010

IR 05000416-06-010; Entergy Operations, Inc; 05/17/06 - 08/07/06; Grand Gulf Nuclear Station -- Other Activities

ML062410054
Person / Time
Site:	Grand Gulf
Issue date:	08/28/2006
From:	Kennedy K NRC/RGN-IV/DRP/RPB-C
To:	Brian W Entergy Operations
References
IR-06-010
Download: ML062410054 (24)

Text

ust 28, 2006

SUBJECT:

GRAND GULF NUCLEAR STATION - NRC SPECIAL INSPECTION REPORT 05000416/2006010

Dear Mr. Brian:

On August 7, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed a special inspection at your Grand Gulf Nuclear Station facility. The enclosed inspection report documents the inspection findings, which were discussed on August 7, 2006, with Mr. M. Krupa, Director, Nuclear Safety Assurance, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

Specifically, the inspectors reviewed the circumstances surrounding the failure of the Division 1 standby diesel generator on May 11, 2006.

This report documents one NRC identified finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements; however, because of its very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a noncited violation (NCV) consistent with Section VI.A of the NRC Enforcement Policy. If you contest this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Grand Gulf Nuclear Station facility.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component

Entergy Operations, Inc. -2-of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Kriss M. Kennedy, Chief Project Branch C Division of Reactor Projects Docket: 50-416 License: NPF-29 Enclosure:

Inspection Report 05000416/2006010 w/Attachment: Supplemental Information Special Inspection Charter cc w/enclosure:

Senior Vice President and Chief Operating Officer Entergy Operations, Inc.

P.O. Box 31995 Jackson, MS 39286-1995 Wise, Carter, Child & Caraway P.O. Box 651 Jackson, MS 39205 Winston & Strawn LLP 1700 K Street, N.W.

Washington, DC 20006-3817 Jay Barkley, Chief Energy & Transportation Branch Environmental Compliance and Enforcement Division Mississippi Department of Environmental Quality P.O. Box 10385 Jackson, MS 39289-0385 President, District 1 Claiborne County Board of Supervisors P.O. Box 339 Port Gibson, MS 39150

Entergy Operations, Inc. -3-General Manager Grand Gulf Nuclear Station Entergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150 The Honorable Charles C. Foti, Jr.

Attorney General Department of Justice State of Louisiana P.O. Box 94005 Baton Rouge, LA 70804-9005 Governor Haley Barbour Office of the Governor State of Mississippi P.O. Box 139 Jackson, MS 39205 Jim Hood, Attorney General State of Mississippi P.O. Box 220 Jackson, MS 39225 D

SUMMARY OF FINDINGS

IR 05000416/2006010; 05/17/06 - 08/07/06; Grand Gulf Nuclear Station -- Other Activities.

The report documents special inspection activities conducted by a senior project engineer, senior reactor inspector, and an operations engineer. The inspection identified one Green finding which was also a noncited violation. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management's review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

Green.

A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI,

"Corrective Actions," was identified for the failure of licensee personnel to preclude repetition of a significant condition adverse to quality. Specifically, the licensee failed to take actions to prevent subsequent standby diesel generator engine head failures attributed to corrosion fatigue in 1992, 1996, and 2006. This issue was entered into the licensee's corrective action program as Condition Report CR-GGN-2006-1955.

The finding was more than minor since it affected the Mitigation System Cornerstone attribute of availability and reliability of mitigating equipment, specifically the standby diesel generators. Using Manual Chapter 0609, Significance Determination Process,

Phase 1 Worksheets, the finding is of very low safety significance since it only involved the loss of one train of diesel generators for less than the Technical Specification allowed outage time (Section 4.b).

Licensee-Identified Violations

None

REPORT DETAILS

4OA5 Other Activities

Division 1 Standby Diesel Generator (SDG) Exhaust Valve Failure

1. Description of SDGs and a Historical Perspective

SDG 11 is a Transamerica Delaval, Incorporated (TDI) engine initially rated at 7000 kw and subsequently derated to 5740 kw because of concerns associated with the load capacity of the crankshaft and piston skirts. The engine is a 16-cylinder, 4-stroke, turbocharged, 45o V-type, DSRV-4 series designed to operate at 450 revolutions per minute.

The diesel generators manufactured for nuclear plants by TDI experienced numerous deficiencies, starting in the 1980's, associated with problems in design, manufacturing, and quality assurance. Based on these problems, the industry formed an owners group to address operational issues and regulatory issues associated with the diesel generators. The NRC staff concluded in NUREG-1216, Safety Evaluation Report Related to the Operability and Reliability of Emergency Diesel Generators Manufactured by Transamerica Delaval, Inc., August 1986, that the actions recommended by the owners plus additional actions described in NUREG-1216 would ensure that the diesel generators would meet regulatory requirements. These requirements were incorporated into the Grand Gulf Nuclear Station facility operating license as a license condition in 1986 and were subsequently removed in 1995 by an approved license amendment.

Among the problems associated with these diesel generators, NUREG-1216 acknowledged that the Groups I and II cylinder heads manufactured before October 1980 were prone to manufacturing defects and susceptible to cracking from pre-existing flaws. Group III heads manufactured after September 1980 were determined to be much less susceptible to manufacturing defects and, therefore, pre-existing flaws. However, it was determined that all heads were adequate for service at nuclear power plants, even though Groups I and II heads had the potential for pre-existing flaws. As a result of the susceptibility of Groups I and II cylinder heads to cracking, the licensee was required to perform prestart and poststart air rolls with the cylinder stopcocks open to check for the presence of water. Currently, SDG 11 has 9 Group I heads and 7 Group III heads, while SDG 12 has 4 Group I heads and 12 Group III heads.

Although the NRC recognized and accepted (in NUREG 1216 and license conditions)that Group I heads were more likely to crack, the NRC attributed this to potential manufacturing defects. The NRC determined that, if a cracked head leaked water into the engine cylinder, immediate corrective action to replace the head had to be taken to ensure the emergency start capability of the engine.

2. Sequence of Events

a. Inspection Scope

The inspectors developed a sequence of events related to the May 11, 2006, Division I SDG mechanical failure and compared it to the licensees sequence of events to determine if the event had been adequately reviewed.

b. Timeline 0358 hours0.00414 days <br />0.0994 hours <br />5.919312e-4 weeks <br />1.36219e-4 months <br />, May 10, 2006: Began a planned maintenance outage on the SDG 11 that was scheduled for 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br />.

1630 hours0.0189 days <br />0.453 hours <br />0.0027 weeks <br />6.20215e-4 months <br />, May 11, 2006: Routine maintenance and modification work was successfully completed.

1647 hours0.0191 days <br />0.458 hours <br />0.00272 weeks <br />6.266835e-4 months <br />, May 11, 2006: Commenced SDG 11 retest. Twenty minutes into a loaded maintenance retest, SDG 11 tripped (Condition Report CR-GGN-2006-1948) and a Hi Vibration alarm was received. Engineering, operations, and maintenance personnel met to discuss the potential causes of the trip and actions necessary to determine the actual cause. The first portion of the troubleshooting plan was to check the vibration switches to determine if any had tripped. Investigation revealed that the left bank turbocharger vibration switch was in a tripped state. Since no abnormal noises/indications were observed locally by operators, maintenance personnel, or engineers during the event, it was assumed that the vibration switch was faulty.

1800 hours0.0208 days <br />0.5 hours <br />0.00298 weeks <br />6.849e-4 months <br />, May 11, 2006: The licensee initiated Work Order 87726 to replace the vibration switch. During the retest run, vibration readings were taken manually, and no abnormal vibration readings were observed; however, the governor was observed to be hunting and abnormal cylinder exhaust temperature readings were observed. The expected range for cylinder exhaust temperatures is 760 to 960oF. The abnormal readings were: Cylinder 8L approximately 320oF, Cylinder 1L approximately 1190oF, and Cylinder 3R approximately 1015oF (Condition Report CR-GGN-2006-2165).

0000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />, May 12, 2006: The diesel generator was started and was run for approximately 36 minutes to vent the oil side of the governor. Only a slight improvement in eliminating the hunting on the governor was noted.

0216 hours0.0025 days <br />0.06 hours <br />3.571429e-4 weeks <br />8.2188e-5 months <br />, May 12, 2006: Since there was only a slight improvement, a nonexcited run was performed to vent the governor. The additional venting resulted in no further improvement in governor performance. The licensee ran SDG 11 for approximately 35 minutes.

0313 hours0.00362 days <br />0.0869 hours <br />5.175265e-4 weeks <br />1.190965e-4 months <br />, May 12, 2006: An emergency start was performed to allow completion of the postmodification testing. The engine was run unloaded for approximately 9 minutes.

0800 hours0.00926 days <br />0.222 hours <br />0.00132 weeks <br />3.044e-4 months <br />, May 12, 2006: A Kepner Tregoe team was formed to identify potential causes for SDG 11 load swings and abnormal cylinder temperatures. The licensee

determined that the most likely causes were blockage of combustion air flow into Cylinder 8L, a stuck fuel injector in Cylinder 8L, or some other mechanical problem.

The combustion air path for Cylinder 8L was inspected and no blockage was found.

The fuel injector was removed and a boroscopic inspection of the cylinder revealed that one of the two exhaust valves (the left valve or Valve A) was broken, with approximately a quarter of the valve face missing. Condition Report CR-GGN-2006-1955 was initiated to document the finding.

May 13, 2006: Cylinder head 8L assembly was removed from the engine. Visual inspection of the head assembly revealed not only the broken exhaust valve (Valve A),but that the other exhaust valve (Valve B) also had cracks in similar locations. Near the exhaust Valve B port, there was visual evidence of a jacket water leak into the cylinder.

No evidence of cracking was visible on either of the intake valves. There was no visual evidence of abnormal seating conditions (e.g., excessive seating forces or asymmetrical seating patterns) to indicate problems (e.g., previous improper installation) related to valve guides, lifters, or valves. The missing portion of the exhaust valve face was found lodged in the stationary vanes of the turbocharger. The engine tripped as a result of high vibration caused by the impact of the exhaust valve face on the turbocharger.

May 19, 2006: The licensee replaced the Cylinder 8L liner, piston rings, head, and valves and performed other inspections to check for other damage to the engine. The retest and surveillance run of SDG 11 was completed and the diesel was declared operable early on May 20. The 4-hour and 24-hour poststart air rolls were completed with no indication of water. The air rolls were conducted using Kolor Kut water detecting paste applied to indicator plates installed adjacent to the cylinder petcocks.

May 23, 2006: After the return of SDG 11 to service, a boroscope inspection of all cylinders on SDG 12 was conducted to determine the potential extent of condition. No visual evidence was found of any jacket water leaks in any cylinder, or of any visible cracking in any exhaust valves. Air rolls of SDG 12 were performed using the Kolor Kut water detecting paste described above with no indications of water noted.

c. Findings

No findings of significance were identified.

3. Operator Response

a. Inspection Scope

The inspectors evaluated the adequacy of the operator response to this event. The sequence of events log, annunciator report, and operator logs were reviewed. The inspectors also interviewed the system engineer, SDG 11 operators, and nuclear equipment operators that were on duty at the time of the event.

b. Findings

No findings of significance were identified.

4. SDG 11 Exhaust Valve Failure Analysis and Root Cause Determination

a. Inspection Scope

The inspectors reviewed root cause analysis Condition Report CR-GGN-2006-1955 in detail and interviewed members of the licensee staff, including members of the root cause team, the system engineer, maintenance personnel, and plant operators. In addition, one NRC special inspection team member observed portions of the destructive and nondestructive examinations performed on the valves and cylinder head at the off-site failure analysis lab.

The inspectors reviewed the licensees sequence of events, operating experience, maintenance history, and metallurgical issues associated with this valve failure and previous diesel generator head failures. The inspectors examined the failed exhaust valve and failed cylinder head. The inspectors reviewed the results of previous lube oil and fuel oil analyses, the maintenance history of SDG 11, plant computer data, performance monitoring data, engine operating logs, a previous overhaul work order, and maintenance rule failure and trending data.

The inspectors also reviewed both internal and external operating experience to determine if there were any similar failures of engine valves or preventive maintenance requirements to prevent such failures.

b. Findings

Root Cause Assessment

Introduction:

The inspectors identified a Green noncited violation (NCV) for failure to prevent recurrence of SDG cylinder head cracking.

Description:

On May 13, 2006, the licensee identified a jacket water leak in SDG 11, Cylinder Head 8L. The inspector observed the metallurgical examination of Cylinder Head 8L and associated exhaust valves. The licensee performed a detailed examination of the fracture surfaces of the through-wall crack in Cylinder Head 8L. The examination revealed a fatigue crack morphology with identified copper and zinc deposits. The licensee concluded that the crack initiation site resulted from galvanic corrosion and the cracks propagated as a result of cyclic stresses (corrosion fatigue).

The inspector also reviewed the licensees examination of the crack surface on the failed valve. The licensee determined that valve failure was due to intergranular corrosion. This was deduced based on the fact that the crack was entirely along the grain boundaries and that the grain boundaries were high in carbides. The presence of carbides in the grain boundary region was indicative of sensitization due to high temperatures. The licensee concluded that the sulphur from the fuel combined with the moisture that leaked into the cylinder through the crack in the cylinder head, caused the formation of polythionic sulphurous acids which preferentially attacked the sensitized grain boundaries, resulting in crack growth on the exhaust valve.

Over the past 23 years, SDG 11 has experienced a total of four failed Group I cylinder heads (current issue, 1996, 1992, and 1984) where jacket water leaked into the cylinder.

For SDG 11, a total of 15 cylinder heads have been replaced for various reasons, including 7 heads for either cracks or indicated flaws. For SDG 12, a total of 17 cylinder heads have been replaced for various reasons; however, only 1 head appears to have been replaced for a water leak. It is important to note that the documentation did not always specify the reason for the cylinder head replacement, so there were potentially more heads replaced due to cracks and flaws than recorded.

The cracked heads from 1984 and 1992 (the 1996 cracked head was not examined)were metallurgically examined and the licensee concluded that the cracks occurred due to corrosion fatigue. The galvanic corrosion was related to chemical additions to the jacket water system. Prior to 1986, nitrite was added to the jacket water to control corrosion. However, the nitrite caused high copper content in the water and set up the galvanic corrosion cells in the jacket water passages of the cylinder heads. These galvanic corrosion cells were the crack initiators. The jacket water chemistry was changed to a molybdate-based additive in 1986 as part of a corrective action following the 1984 head failure. Even though the jacket water chemistry program was changed, the subsequent head failure and jacket water leak in 1992 was determined to be caused by the same failure mechanism. The licensee did not destructively examine the cracked head in 1996, but attributed the failure to corrosion fatigue. With the exception of changing the jacket water chemistry in 1986, the licensee took no additional corrective actions to mitigate, predict, or prevent additional failures of cylinder heads due to this failure mechanism.

Analysis:

The licensee failed to take corrective actions to prevent recurrence of cracked cylinder heads due to corrosion fatigue initiated by improper jacket water chemistry control, especially after the 1992 and 1996 cracked cylinder heads. In both instances, the licensee replaced the heads and took no additional corrective actions to prevent recurrence. This finding affected the Mitigating System Cornerstone since the SDGs are required to mitigate the consequences of an accident. The finding was more than minor since it affected the cornerstone attribute of availability and reliability of mitigating equipment. The finding was determined to be of very low safety significance based on Phase 1 of the Significance Determination Process screening, since it involved the loss of only one train of diesel generators for less than the Technical Specification allowed outage time. The licensee performed an evaluation and determined that the SDG could have continued to operate and supply electrical loads as designed for 30 days even with the broken exhaust valve. The inspectors reviewed and agreed with the evaluation.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, requires that measures shall be established to assure that conditions adverse to quality, such as failures and malfunctions, are promptly identified and corrected. In the case of significant conditions adverse to quality, measures shall be taken to assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to this requirement, Grand Gulf Nuclear Station failed to correct and preclude repetition of a significant condition adverse to quality. Specifically, the licensee failed to take actions to prevent subsequent head failures attributed to corrosion fatigue in 1992, 1996, and 2006. This violation, which was determined to have a very low safety significance and was entered into the licensees corrective action program as Condition Report

CR-GGN-2006-1955, is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000416/2006010-01, Inadequate Corrective Actions for SDG Cylinder Head Cracks.

Extent of Condition Based on the root and contributing causes for this failure, the inspectors determined that SDGs 11 and 12 are susceptible to exhaust valve failures because the valve material is susceptible to intergranular corrosion cracking and the valves currently installed are of the same material. In addition, both SDGs have Group I heads that are known to have the potential for defects, as well as some Group I heads that were exposed to the original nitrite jacket water chemistry control program and associated high copper concentrations, which has been attributed to being the crack initiator on four previous SDG 11 cracked heads. The licensee has implemented actions to identify the presence of cracked cylinder heads and are evaluating additional corrective actions, as described below, to prevent another exhaust valve failure.

5. Corrective Actions Implemented Following the May 2006 Event

Cylinder Head 8L was removed from the engine and both intake and exhaust valves were removed and sent to an offsite laboratory for metallurgical examination. In addition, the licensee sent similar valves from the warehouse and valves from another site for comparison. The licensee also pressure tested the jacket water passages for leaks. No leaks were discovered.

The licensee disassembled and inspected the left bank turbocharger for damage and found only cosmetic damage, which was caused by the impact of the broken section of the exhaust valve on the stationary turbocharger vanes. Cylinder Liner 8L was replaced due to corrosion found under the glazing (unrelated to valve failure). The piston was removed, inspected, cleaned, and reinstalled. In addition, the piston rings, cylinder head, and all four valves were replaced. The remaining 15 cylinders were inspected using a boroscope and no other visible valve cracking or jacket water leaks were identified.

In addition to the immediate corrective actions to repair the diesel, the licensee instituted two interim corrective actions to identify any future jacket water leaks into the cylinders:

• Boroscopic inspections are planned for each of the Group I cylinders to look for water leaks or valve cracking through January 2007. The quarterly inspection schedule was determined based on the licensees estimated crack growth time of approximately 14 weeks. The licensee estimated this period of time based on corrosion indications on the cylinder liner and best guess estimates of corrosion rates. The inspectors concluded that the licensees method for calculating corrosion rates was at best a crude method, but seemed reasonable, since no other test or historical data were available to either support or refute the licensees estimated valve crack growth rate.

• Monitor for small amounts of water in the cylinder by using a water sensitive paste applied to aluminum plates installed in front of each engine cylinder petcock.

The inspectors found that these actions appeared to be technically acceptable and appropriate. Though the inspectors were unable to predict with certainty the effectiveness of the current interim measures, the inspectors verified that they were being performed and/or have been incorporated into licensee procedures.

6. Additional Long-Term Corrective Actions Planned (by end of 2006)

The inspectors also noted that the licensee planned to implement the following long-term corrective actions related to the SDG 11 exhaust valve failure:

• Identify and evaluate a method to detect small quantities of jacket water in the lube oil.

• Establish new valve material specification and install new valves.

• Establish a long-range reliability plan for the heads, including the strategy for replacing all Group I heads with Group III heads.

• Identify and evaluate changes in jacket water chemistry controls that might reduce head crack growth rate.

The inspectors determined that the licensee had planned appropriate long-term corrective actions to prevent a similar valve failure from recurring.

7. SDG Monitoring and Maintenance

a. Inspection Scope

The inspectors reviewed the maintenance history, nondestructive examination records, SDG preventive maintenance program, maintenance packages for the last overhaul of both SDGs, and licensee testing to identify cylinder leakage for the Divisions I and II SDGs. The inspectors reviewed data of numerous maintenance and surveillance engine tests for both SDGs. In addition, the inspectors reviewed cylinder pressure and exhaust temperature data, fuel oil receipt analysis, and fuel oil tank inspections to verify that acceptance criteria were met. Additional documents reviewed by the inspectors are listed in the attachment.

The inspectors concluded that the maintenance and testing activities performed by the licensee were adequate and none of the information reviewed indicated the potential of the exhaust valve failure.

b. Findings

No findings of significance were identified.

8. Testing Program to Confirm Operability of SDG 11 Following Repair Activities

a. Inspection Scope

The inspectors reviewed the postmaintenance test activities following the repair of the SDG 11. The inspectors:

(1) reviewed the applicable licensing and design basis documents to determine the safety functions;

(2) evaluated the safety functions that may have been affected by the repair activities; and

(3) reviewed the test procedure to ensure it adequately tested the safety functions that may have been affected. The inspectors witnessed portions of the retest of the SDG, including test runs and inspections of the diesel at various loads used to seat the new piston rings, an unloaded run of the diesel, and a monthly surveillance run of the diesel per Technical Specification Surveillance Requirement 3.8.1.3. In addition, the inspectors reviewed test data to verify that acceptance criteria were met, plant impacts were evaluated, test equipment was calibrated, procedures were followed, test data results were complete and accurate, test equipment was removed, the system was properly re-aligned, and deficiencies during testing were documented. The inspectors also reviewed the Updated Final Safety Analysis Report to determine if the licensee identified and corrected problems related to the postmaintenance testing. Additional documents reviewed by the inspectors are listed in the attachment.

The inspectors concluded that the testing activities performed by the licensee were adequate to confirm the operability of SDG 11 following the repair activities.

b. Findings

No findings of significance were identified.

9. Industry Operating Experience

a. Inspection Scope

The inspectors reviewed various NRC generic communications and operating experience from other licensees relevant to TDI diesel generators. Specifically, the inspectors reviewed NUREG-1216, Safety Evaluation Report Related to the Operability and Reliability of Emergency Diesel Generators Manufactured by Transamerica Delaval, Inc., August 1986, and other generic documents listed in the appendix. The inspectors also performed internet searches for similar types of valve failures on non-nuclear industrial diesel generators. No relevant valve failures of this type were identified in either nuclear or industrial diesel generators. However, several reports discussed concerns with exhaust valves. One report dealing with marine diesel engines did note that exhaust valves have the highest failure rates for the propulsion system, but no discussion of failure mechanisms were included. Another report indicated that the center area of an exhaust valve experiences the hottest temperatures and is most susceptible to corrosion (no analytical data provided, only qualitative).

The inspectors did note that Group I head failures were expected to occur and that proper testing was put in place to identify gross cylinder water leakage before diesel generator operability would be compromised. However, the testing was not designed to

identify very small jacket water leaks that would be required to form the conditions necessary for the sulfurous acid to cause the intergranular corrosion cracking mechanism to occur. This particular environment necessary for the sulfurous acid corrosion mechanism was not recognized or known to occur.

b. Findings

No findings of significance were identified.

10.

Potential Common Failure Mode and Generic Safety Issues The potential exists for exhaust valves to crack in both SDGs 11 and 12. Both engines were manufactured by Transamerica Delaval and the engines have the same valve material and same Group I heads that were found broken and cracked. In addition to the through-wall cracks, the licensee also identified numerous nonthrough-wall cracks in the other exhaust port on the failed 1984, 1992, and 2006 heads due to the same failure mechanism. The cracks were similar in length to the through-wall cracks, but had not become through-wall because the wall thickness of these ports was at or above the minimum wall thickness specification of 0.500 inches. The through-wall cracks occurred in the SDG 11 exhaust port areas with the following thicknesses: Cylinder Head 7L (1984 failure) 0.250 inches, Cylinder Head 2R (1992 failure) 0.325 inches, and Cylinder Head 8L (2006 failure) 0.350 inches. None of the identified cracks were initiated as a result of manufacturing defects as was the original concern in NUREG-1216; therefore, based on this information, the inspectors determined that any head exposed to the high copper concentration is susceptible to a similar failure mechanism.

There are 20 TDI diesel generators currently in use in the nuclear industry. The inspectors concluded that other TDI engines are susceptable to failure of exhaust valves if similar conditions exist. However, Grand Gulf Nuclear Station has taken corrective actions to identify the adverse conditions prior to valve failure. The licensee informed other nuclear utilities of the exhaust valve failure through the utilitys operating experience network and indicated that they are planning to submit a voluntary licensee event report.

4OA6 Meetings, Including Exit

On August 7, 2006, the results of this inspection were presented to Mr. M. Krupa and other members of his staff who acknowledged the findings. The inspector confirmed that the supporting details in this report contained no proprietary information.

ATTACHMENTS:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Bottemiller, Manager, Plant Licensing

R. Bryan, General Manager, Plant Operations

W. Eaton, Vice President, Engineering, Entergy Operations Incorporated

P. Griffith, Senior Engineer

D. Jones, Engineering Supervisor

M. Krupa, Director, Nuclear Safety Assurance

J. Owens, Senior Licensing Specialist

D. Wiles, Director, Engineering

NRC personnel

A. Barrett, Resident Inspector, Reactor Project Branch C

R. Bywater, Senior Reactor Analyst

J. Groom, Reactor Inspector, Engineering Branch 1

G. Miller, Senior Resident Inspector, Reactor Project Branch C

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000416/2006010-01 NCV Inadequate Corrective Actions for SDG Cylinder Head Cracks (Section 4.b.)

Closed

None

Discussed

None Attachment 1