IR 05000416/2006008

IR 05000416-06-008; January 30 Through March 10, 2006; Grand Gulf Nuclear Station: Baseline Inspection, NRC Inspection Procedure 71111.21, Component Design Basis Inspection

ML061070259
Person / Time
Site:	Grand Gulf
Issue date:	04/13/2006
From:	Clark J Division of Reactor Safety IV
To:	Gerald Williams Entergy Operations
References
IR-06-008
Download: ML061070259 (37)

Text

ril 13, 2006

SUBJECT:

Grand Gulf Nuclear Station - NRC INSPECTION REPORT 05000416/2006-008

Dear Mr. Williams:

On February 13 through March 10, 2006, the US Nuclear Regulatory Commission (NRC)

conducted an inspection at your Grand Gulf Nuclear Station. The enclosed report documents the inspection findings which were discussed on March 27, 2006, with Mr. D. Wiles, Director, Engineering, 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.

The inspectors reviewed selected procedures and records, observed activities, and interviewed cognizant plant personnel.

Based on the results of this inspection, the NRC has identified two issues that were evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has also determined that violations are associated with these issues which are being treated as noncited violations, consistent with Section VI.A.1 of the Enforcement Policy. These noncited violations are described in the subject inspection report. If you contest the violation or significance of these noncited violations, 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; 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 and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's

Entergy Operations, Inc. -2-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/

Jeffrey A. Clark, PE, Chief Engineering Branch 1 Division of Reactor Safety Docket: 50-416 License: NPF-29

Enclosure:

Inspection Report 05000416/2006-008 w/Attachment: Supplemental Information

REGION IV==

Docket: 50-416 License: NPF-29 Report No.: 05000416/2006-008 Licensee: Entergy Operations, Inc.

Facility: Grand Gulf Nuclear Station Location: Waterloo Road Port Gibson, Mississippi Dates: February 13 through March 10, 2006 Team Leader: C. Paulk, Senior Reactor Inspector Engineering Branch 1 Inspectors: P. Gage, Senior Operations Engineer G. George, Reactor Inspector J. Nadel, Reactor Inspector E. Owen, Reactor Inspector J. Reynoso, Reactor Inspector W. Sifre, Senior Reactor Inspector Contractors: F. Baxter, Electrical, Beckman and Associates M. Yeminy, Mechanical, Beckman and Associates Approved By: J. Clark, PE, Chief Engineering Branch 1 Enclosure

SUMMARY OF FINDINGS

IR 05000416/2006-008; January 30 through March 10, 2006; Grand Gulf Nuclear Station:

baseline inspection, NRC Inspection Procedure 71111.21, Component Design Basis Inspection.

The report covers an announced inspection by a team of seven regional inspectors and two contractors. Two findings of very low safety significance were identified. The significance of most findings is indicated by its color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRC's 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.

The team identified a finding of very low safety significance involving a noncited violation of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for the failure to implement a testing program to demonstrate the ability of standby service water-cooled heat exchangers to perform their design basis functions under all conditions.

The finding is greater than minor because, if left uncorrected, it would lead to a more significant issue, namely a heat exchanger would become unable to fulfill its safety function due to excessive fouling accumulating during the time between testing. This finding has cross-cutting aspects because it is more than minor, it represents current performance, and the cause is directly associated with the problem identification and resolution attribute of evaluation of test data Using the NRC Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Screening Worksheet, the team determined this finding to be of very low safety significance (Green) since it was associated with the equipment performance attribute of the mitigating systems cornerstone and was a design or qualification deficiency that did not result in a loss of function in accordance with NRC Inspection Manual Part 9900, Operable/Operability:

Ensuring the Functional Capability of a System or Component, (formerly Generic Letter 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability).

Because the finding is of very low safety significance (Green) and has been entered into the licensee personnels corrective action program as Condition Reports 2006-00834, 2006-00852, 2006-00864, 2006-00952, 2006-00959, and 2006-00960, this violation is being treated as a noncited violation, consistent with Section VI.A.1 of the Enforcement Policy: NCV 05000382/2006008-01,

Inadequate Test Control Program for Standby Service Water-Cooled Heat Exchangers. (Section 1R21b.1.)

Green.

The team identified a finding of very low safety significance for a noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to translate all design basis information into specifications and procedures were not adequate to assure that instrument uncertainties were correctly accounted for in the development of Technical Specification values or in the surveillance test acceptance criteria.

The team determined this finding to be greater than minor because, similar to an example in MC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the failure of licensee personnel to demonstrate where, and how, instrument uncertainties were translated into either Technical Specification values or the surveillance test acceptance criteria could result in systems and/or components not being capable of performing design basis functions. This finding has cross-cutting aspects because it is more than minor, the failure to correct a previously identified adverse condition is an ongoing performance deficiency, and the cause (i.e., not understanding how to address instrument uncertainties) is directly associated with the problem identification and resolution attribute of corrective actions.

The finding affected the procedure quality attribute of the mitigating systems cornerstone. Using the Manual Chapter 0609 Phase 1 Worksheet, the team determined that this finding had very low safety significance (Green) because there was no loss of operability or safety function and it did not involve an external event.

Because the finding is of very low safety significance (Green) and has been entered into the licensees corrective action program as Condition Report 2006-01191, this violation is being treated as a noncited violation, consistent with Section VI.A.1 of the Enforcement Policy: NCV 05000382/2006008-02, Failure to Translate Design Basis Information into Specifications and Procedures. (Section 1R21b.2.)

REPORT DETAILS

REACTOR SAFETY

Inspection of component design bases verifies the initial design and subsequent modifications and provides monitoring of the capability of the selected components and operator actions to perform their design bases functions. As plants age, their design bases may be difficult to determine and an important design feature may be altered or disabled during a modification. The plant risk assessment model assumes the capability of safety systems and components to perform their intended safety function successfully. This inspectable area verifies aspects of the Initiating Events, Mitigating Systems and Barrier Integrity cornerstones for which there are no indicators to measure performance.

1R21 Component Design Bases Inspection

The team selected risk-significant components and operator actions for review using information contained in the licensees probabilistic risk assessment. In general this included components and operator actions that had a risk achievement worth factor greater than two or Birnbaum value greater than 1E-6.

a. Inspection Scope

To verify that the selected components would function as required, the team reviewed design basis assumptions, calculations, and procedures. In some instances, the team performed independent calculations to verify the appropriateness of the licensee engineers' analysis methods. The team also verified that the condition of the components was consistent with the design bases and that the tested capabilities met the required criteria.

The team reviewed maintenance work records, corrective action documents, and industry operating experience information to verify that licensee personnel considered degraded conditions and their impact on the components. For the review of operator actions, the team observed operators during simulator scenarios associated with the selected components, as well as observing simulated actions in the plant.

The team performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design issues, margin reductions due to modification, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as failed performance test results; significant corrective actions; repeated maintenance; 10 CFR 50.65(a)1 status; operable, but degraded, conditions; NRC resident inspector input of problem equipment; system health reports; industry operating experience; and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins.

The inspection procedure requires a review of 15-20 risk-significant and low design margin components, three to five relatively high-risk operator actions, and four to six operating experience issues. The sample selection for this inspection was 17 components, five operator actions, and six operating experience items.

The components selected for review were:

• Automatic depressurization system safety-relief valve

• Condensate storage tank level indication

• Division 1 125Vdc battery

• Division 1 emergency diesel generator load capability

• Division 1 emergency load sequencer

• Division 3 emergency diesel generator ventilation fan/cooler

• Emergency diesel generator jacket water temperature controller

• Emergency diesel generator lubricating oil filter

• High pressure core spray pump room cooler

• High pressure core spray pump

• Low pressure core spray pump

• Reactor core isolation cooling pump

• Residual heat removal/low pressure core injection pump

• Standby liquid control system relief valve

• Standby service water cooling tower siphon pipe

• Secondary Containment Isolation Valve M41-F037

• Instrument Air Secondary Containment Isolation Valve P53-F026B The selected operator actions were:

• Alternate boration for the Standby Liquid Control system

• Cross-tie of the Division 3 electrical bus with the Division 1 electrical bus

• Reset of the reactor core isolation cooling trip/throttle valve

• Restoration of the instrument air system

• Restoration of the standby service water system The operating experience issues were:

• Alternate boration during an anticipated transient without a scram

• Component cooling water butterfly valves

• Demonstration of accountability for uncertainties in the establishment of acceptance criteria

• Double acting air operated valves, as identified in a Grand Gulf Nuclear Generating Station operator workaround condition

• Reactor core isolation cooling trip throttle valve

• Reactor recirculation system optical isolators

b. Findings

b.1. Inadequate Test Control Program for Standby Service Water-Cooled Heat Exchangers

Introduction.

A violation of very low safety significance (Green) was identified for failure to properly demonstrate the Division I, II, and III emergency diesel generators jacket water heat exchangers, and the high pressure core spray pump room cooler were able to remove their design heat loads under all conditions.

Description.

In their response to Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment, licensee personnel committed to a testing and trending program for their standby service water-cooled heat exchangers. Specifically, they responded that an 18-month testing frequency would be established for at least three cycles and any extensions of the testing frequency would be based on an appropriate trend in the data.

The team noted that testing of the standby service water-cooled heat exchangers began in 1990. The team looked specifically at five of these heat exchangers, namely the Division I and Division II diesel generator jacket water cooling heat exchangers, both of the Division III jacket water cooling heat exchangers, and the high pressure core spray room cooler. The Division I and II jacket water heat exchangers are identical. The Division III diesel generator has two identical jacket water cooling heat exchangers that are much smaller than their Division I and II counterparts. The Division III diesel generator serves only the high pressure core spray system loads and has a smaller load rating and thus a smaller jacket water cooling requirement than Divisions I and II. The high pressure core spray system room cooler is an air-to-water heat exchanger that ensures the high pressure core spray pump will fulfill its safety function by keeping the room temperature below design limits.

The Division I, II, and III jacket water heat exchangers were tested about every 18 months, using the same methodology, from 1990 until 2000. In 2000, a new testing methodology was adopted using more accurate temperature instruments to improve the test data.

In 2002, licensee engineers extended the testing frequency for these heat exchangers to 4 years from their previous 18-month cycle. The team concluded that, although the initial testing frequency remained in place for 12 years before it was extended, licensee personnel were unable to establish an adequate trend in that time. This conclusion was based, in part, on the use of an average of the calculated heat removal capacity from the previous tests (including invalid data) and also on the fact that the data scatter was too large to establish a meaningful trend (see Tables 1, 2, 3, and 4).

The team learned that the licensee engineers based their decision to extend the time period between tests on the average being greater than 100 percent for each heat exchanger. The team found the use of the average heat removal capacity values was not supported by good engineering judgement. The team found no attempt by licensee engineers to trend the data at any time during their testing of these heat exchangers.

The team noted that the first test of the Division I jacket water heat exchanger should have been classified as a failure (Table 1) and corrective actions should have been taken. However, licensee engineers did not consider the test a failure and took no corrective actions. Even though there were no corrective actions, the fouling factor improved from 1993 to 1997. Without a cleaning performed on the heat exchanger the team did not expect such an improvement in heat removal capacity. Results showed a relatively stable heat removal capacity of around 110 percent for tests from 1998 to 2000. In 2004 the capacity decreased to 102 percent.

The team performed independent analysis on the data in Table 1 and concluded that the heat removal capacity would decrease below the 100 percent value anywhere from January 2005 to February 2006. The Division I heat exchanger has never been cleaned. A cleaning is currently planned in May 2006.

Table 1 Division I Jacket Water Heat Exchanger Performance Testing Results (Data taken from ER-GG-2002-0058, Revision 0)

Projected Heat Transfer Design Required Percent Fouling Rate Heat Transfer Design Test Date Factor (BTU/hr) Rate (BTU/hr) Capacity 09/25/1992 0.000258 1.086E+07 1.930E+07 56.27%

10/18/1993 0.000840 2.620E+07 1.930E+07 135.75%

04/17/1995 0.001900 2.807E+07 1.930E+07 145.43%

03/12/1997 0.000852 2.919E+07 1.930E+07 151.24%

10/20/1998 0.002400 2.142E+07 1.930E+07 110.98%

05/2/2000 0.002500 2.151E+07 1.930E+07 111.45%

Average = 118.52%

02/16/2004 0.002980 1.969E+07 1.930E+07 102.0%

The team noted that the results for the Division II jacket water heat exchanger test data also showed a failure in 1993 without any corrective actions taken by licensee personnel. From 1995 through 2001, the team saw that there was a steady decline in the heat removal capacity with a relatively constant fouling factor. The last test,

performed in 2001, indicated the heat exchanger at 110 percent of design heat removal capacity. The team observed that the licensee personnel did not test the Division II jacket water heat exchanger within the 4-year period established in 2002.

As a result of fouling discovered in Division III (Table 4, 6/5/2005), the Division II heat exchanger was cleaned in February 2006; no test data was taken before the cleaning.

This eliminated all trend information since the 2001 test. The heat exchanger was tested immediately after the cleaning as a re-baseline. However, licensee personnel were not successful in measuring accurate temperatures; which resulted in an invalid test. A combination of a freshly cleaned heat exchanger, a temperature sensitive three-way jacket water valve, and low standby service water temperature due to outside ambient air temperatures in February, resulted in insufficient jacket water flow through the heat exchanger. Low jacket water flow resulted in low heat transfer due to a laminar flow regime and inaccurate temperature readings which led to the invalidated test.

The last successful test of Division II was the 2001 test. A new test is planned for May 2006.

Table 2 Division II Jacket Water Heat Exchanger Performance Testing Results (Data taken from ER-GG-2002-0058, Revision 0)

Test Date Fouling Projected Design Required Percent Factor Heat Transfer Heat Transfer Design Rate (BTU/hr) Rate (BTU/hr) Capacity 04/14/1993 0.002970 2.333E+07 1.930E+07 120.88%

11/11/1993 0.002630 1.074E+07 1.930E+07 55.65%

04/15/1995 0.002460 2.547E+07 1.930E+07 131.99%

01/8/1997 0.002830 2.404E+07 1.930E+07 124.54%

08/18/1998 0.002550 2.287E+07 1.930E+07 118.50%

07/17/2001 0.002430 2.136E+07 1.930E+07 110.67%

Average = 110.37%

02/24/2006 Invalid Invalid Invalid Invalid

The team noted that the Division III A and B jacket water heat exchangers have exhibited the most service water side fouling. This was expected because of the smaller size of the heat exchangers.

In June of 2005, licensee personnel tested the A heat exchanger (Table 3). The team noted that the fouling factor was greater than design and that the calculated heat removal capacity was just 100.8 percent of design. At the same time, the B heat exchanger (Table 4) was tested. It also showed greater than design fouling with only an 83.5 percent calculated heat removal capacity.

Licensee personnel performed an operability analysis to determine the status of the Division III emergency diesel generator. The licensee personnel concluded that the component was operable but degraded. On that basis, licensee management deferred cleaning until December 2005. The team found no issues with the operability analysis.

As a result of the fouling removed from the Division III jacket water heat exchangers in December 2005, licensee management scheduled cleaning and inspection of the other divisions during their next scheduled outage.

Table 3 Division III A Jacket Water Heat Exchanger Performance Testing Results (Data taken from ER-GG-2002-0058, Revision 0)

Test Date Fouling Projected Design Required Percent Factor Heat Transfer Heat Transfer Design Rate (BTU/hr) Rate (BTU/hr) Capacity 08/30/1991 0.00098 N/A 5.120E+06 N/A 09/25/1992 0.00097 5.060E+06 5.120E+06 98.83%

04/14/1993 0.00042 8.280E+06 5.120E+06 161.72%

04/24/1995 0.00134 6.522E+06 5.120E+06 127.37%

11/3/1996 0.00108 6.611E+06 5.120E+06 129.12%

03/21/1997 0.00146 6.402E+06 5.120E+06 125.05%

05/2/1998 0.0013 6.562E+06 5.120E+06 128.17%

01/18/2001 0.0017 5.690E+06 5.120E+06 111.13%

Average = 125.97%

Table 3 Division III A Jacket Water Heat Exchanger Performance Testing Results (Data taken from ER-GG-2002-0058, Revision 0)

Test Date Fouling Projected Design Required Percent Factor Heat Transfer Heat Transfer Design Rate (BTU/hr) Rate (BTU/hr) Capacity 06/3/2005 0.00218 5.160E+06 5.120E+06 100.8%

12/16/2005 0.00134 6.093E+06 5.120E+06 119.0%

Table 4 Division III B Jacket Water Heat Exchanger Performance Testing Results (Data taken from ER-GG-2002-0058, Revision 0)

Test Date Fouling Projected Design Required Percent Factor Heat Transfer Heat Transfer Design Rate (BTU/hr) Rate (BTU/hr) Capacity 8/30/1991 0.00138 N/A 5.120E+06 N/A 4/24/1995 0.00173 5.763E+06 5.120E+06 112.56%

3/21/1997 0.00196 5.530E+06 5.120E+06 108.01%

5/2/1998 0.00160 5.942E+06 5.120E+06 116.05%

1/18/2001 0.00170 6.640E+06 5.120E+06 110.16%

Average = 111.69%

6/3/2005 0.00277 4.275E+06 5.120E+06 83.5%*

12/16/2005 0.00139 5.998E+06 5.120E+06 117.1%

• Identified as a test failure The team noted that, in response to Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment, licensee personnel committed to calculate the air flow rate through their high pressure core spray room cooler. This was to be done by measuring various inlet and outlet temperatures and fluid flow rates. The

team observed that licensee engineers met this commitment for the testing performed prior to January 2004. In January 2004, during a test of the high pressure core spray room cooler, licensee personnel measured air flow and used the measurement to calculate the standby service water inlet temperature. This was a change in the commitment provided to the NRC.

Licensee personnel extended the period between tests for the high pressure core spray room cooler to 4 years in 2002 despite the fact that the test performed in 2000 showed a fouling factor greater than the design allowable and no cleaning had been performed.

As with the jacket water heat exchangers, the team found that licensee engineers did not question improved heat removal capacities with an increased fouling factor. Neither did the licensee engineers question improved fouling factors without having performed any cleaning of the heat exchangers.

Analysis.

The team determined that the failure to properly control heat exchanger testing constituted a performance deficiency. Generic letter responses constitute a commitment to the NRC and the failure to comply with that commitment usually results in a deviation. In this case; however, Generic Letter 89-13 described a program acceptable to the NRC that would properly ensure 10 CFR Part 50, Appendix A, General Design Criteria 44, 45, and 46 are being met. The program may either be the one outlined in Enclosure 1 of Generic Letter 89-13, or an equally acceptable alternative.

Licensee engineers chose the program outlined in Enclosure 1, of Generic Letter 89-13, that required testing and trending of the performance of these heat exchangers. The engineers failed to adequately demonstrate that these heat exchangers remained operable between tests because the testing data was never trended. Without trend information, the team found that the licensee engineers had no ability to predict when performance would drop below design basis requirements. This was, in fact, what happened when the Division III diesel generator B jacket water heat exchanger failed its performance testing in June 2005.

The team determined this finding to be greater than minor because if left uncorrected it would lead to a more significant issue, namely a heat exchanger that becomes unable to fulfill its safety function due to excessive fouling accumulating in the time between testing. This finding has cross-cutting aspects because it is more than minor, it represents current performance, and the cause is directly associated with the problem identification and resolution attribute of evaluation of test data.

Using the NRC Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Screening Worksheet, the team determined this finding to be of very low safety significance (Green) since it was associated with the equipment performance attribute of the mitigating systems cornerstone and was a design or qualification deficiency that did not result in a loss of function in accordance with NRC Inspection Manual Part 9900, Operable/Operability: Ensuring the Functional Capability of a System or Component (formerly Generic Letter 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability).

Enforcement.

10 CFR Part 50, Appendix B, Criterion XI, Test Control, states, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service is identified and performed.

Contrary to the above, as of March 10, 2006, the program established to test the standby service water-cooled heat exchangers failed to demonstrate the capability of the heat exchangers to perform their design functions under all conditions. Specifically, the program did not include any requirements for evaluating inconsistent data (i.e.,

improved performance without cleaning, data scatter, etc.). The program also did not address trending and assessing the performance to support the testing period and predict when corrective actions would be necessary to ensure continued capability of the heat exchangers to perform their design functions.

Because the finding is of very low safety significance (Green) and has been entered into the licensees corrective action program as Condition Reports 2006-00834, 2006-00852, 2006-00864, 2006-00952, 2006-00959, and 2006-00960, this violation is being treated as a noncited violation, consistent with Section VI.A.1 of the Enforcement Policy: NCV 05000382/2006008-01, Inadequate Test Control Program for Standby Service Water-Cooled Heat Exchangers.

b.2. Failure to Translate Design Basis Information into Specifications and Procedures

Introduction.

A violation of very low safety significance (Green) was identified for the failure to demonstrate that the acceptance criteria for surveillance tests had appropriately accounted for uncertainties.

Description.

During review of Calculation MC-Q1111-84016, ECCS Pump Surveillance Criteria, Revision 3, the team noted that licensee engineers had not accounted for all uncertainties associated with the high pressure core spray pump. Additionally, the team noted that the engineer had incorrectly included a biased value when calculating the square root of the sum of the squares for those uncertainties that were accounted for.

The team also found that uncertainties were not included in the acceptance criterion for the reactor core isolation cooling pump flow surveillance test.

For the high pressure core spray pump criterion, the team found that, while not accurately included in the calculation, the Technical Specification required flow included sufficient margin to implicitly account for uncertainties. Therefore, Calculation MC-Q1111-84016 was not required to support an indicated value greater than that in the surveillance requirement. However, the team found that neither the criterion provided in the Technical Specification nor the surveillance test for the reactor core isolation cooling pump accounted for any uncertainties.

The issue of accounting for uncertainties was first addressed with Entergy Operations, Inc. (Entergy), during an architect engineering inspection documented in NRC Inspection Report 50-382/98-201 as Unresolved Item 50-382/98201-18. This item was specifically related to the accounting of uncertainties for instruments used to perform in-service testing of pumps and was closed in NRC Inspection Report 50-382/99-06.

However, another unresolved item (50-382/9906-04) was opened to evaluate the

accounting for total loop uncertainties when demonstrating the operability of safety-related pumps. This unresolved item was subsequently closed in NRC Inspection Report 50-382/00-01 (ADAMS Accession ML003697828) on the basis of the Waterford engineers ability to demonstrated adequate margin for the affected components.

A meeting was held on December 2, 1999, with representatives of Entergy to discuss how the organization accounted for uncertainties (ADAMS Accession ML003694170).

During the meeting, Entergy officials agreed that the uncertainties must be addressed in either the technical specification value or the surveillance test acceptance criteria. The manner of how the uncertainties were addressed was discussed in detail.

As a result of the meeting, the NRC found Entergys methodology of a graded approach to be acceptable. This approach allowed for the use of implicit and explicit methods, as well as a range of detail in the documentation of the accounting for the margins.

Explicit methods require the use of calculations and formal evaluation to demonstrate that there is sufficient margin in either the Technical Specification value or the surveillance test procedure acceptance criteria. This method is most straight forward.

Implicit methods utilize more judgement than detailed analyses. For example, at Grand Gulf, the Technical Specification for high pressure core spray flow is 7115 gpm, and the accident analysis uses 6300 gpm to evaluate the accident response. This provides an implied margin of 815 gpm in the Technical Specification value. Using the implicit method would allow a surveillance test acceptance criteria of 7115 gpm without further consideration of uncertainties.

Conversely, if the Technical Specification value did not have any uncertainties built into it, the surveillance test would then need them accounted for in the acceptance criteria.

For example, the Technical Specification for the reactor core isolation cooling pump flow is 800 gpm. There was no consideration of uncertainties in the establishment of this value. Therefore, the surveillance test acceptance criteria would need to include the uncertainties in order to assure that the Technical Specification was satisfied and demonstrate that the pump was operable. The team noted that the actual values attained during the surveillance tests were approximately 830 gpm, which was greater than the estimated uncertainties.

The team noted that engineering personnel at Grand Gulf began a program to address the issue of accounting for uncertainties, but abandoned it before completion. While the work was still in draft form, the team reviewed the effort for the reactor core isolation cooling pump flow and found that the engineers did not understand the issue. The engineers incorrectly concluded that, while there was no explicit demonstration that uncertainties were included in the establishment of the Technical Specification limit, there was no need to include uncertainties in the surveillance test acceptance criteria.

This demonstrated a misunderstanding of the application of uncertainties to assure the demonstration of operability.

Analysis.

The team found that the failure to translate design information (i.e., instrument uncertainties) into specifications and procedures was a performance deficiency.

The team determined this finding to be greater than minor because, similar to an example in MC 0612, Power Reactor Inspection Reports, Appendix E, Examples of Minor Issues, the failure of licensee personnel to demonstrate where, and how, instrument uncertainties were translated into either Technical Specification values or the surveillance test acceptance criteria could result in systems and/or components not being capable of performing its design basis functions. This finding has cross-cutting aspects because it is more than minor, the failure to correct a previously identified adverse condition is an ongoing performance deficiency, and the cause (i.e., not understanding how to address instrument uncertainties) is directly associated with the problem identification and resolution attribute of corrective actions.

The finding affected the procedure quality attribute of the mitigating systems cornerstone. Using the Manual Chapter 0609 Phase 1 Worksheet, the team determined that this finding had very low safety significance (Green) because there was no loss of operability or safety function and it did not involve an external event.

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that measures shall be established to assure that design basis are correctly translated into specifications and procedures.

Contrary to the above, the measures established by licensee personnel to translate design basis information into specifications and procedures were not adequate, as of March 10, 2006, to assure that instrument uncertainties were correctly accounted for in the development of Technical Specification values or in the surveillance test acceptance criteria. Specifically, licensee engineers did not include instrument uncertainties in the development of the Technical Specification for the reactor core isolation cooling pump flow (800 gpm) and established an acceptance criteria of 800 gpm for the demonstration of operability.

Because the finding is of very low safety significance (Green) and has been entered into the licensees corrective action program as Condition Report 2006-01191, this violation is being treated as a noncited violation, consistent with Section VI.A.1 of the Enforcement Policy: NCV 05000382/2006008-02, Failure to Translate Design Basis Information into Specifications and Procedures.

4OA6 Meetings, Including Exit

On March 27, 2006, the team leader presented the inspection results, via telephone, to Mr. D. Wiles, Director, Engineering, and other members of the Grand Gulf Nuclear Stations staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during this inspection

ATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Franklin, Engineering Supervisor, Programs and Components

D. Wilson, Engineering Supervisor, Design Engineering

W. White, Manager, Programs and Components

D. Wiles, Director, Engineering

C. Bottemiller, Manager, Licensing

D. Coulter, Senior Licensing Specialist, Licensing

E. Harris, Manager, Nuclear Safety Assurance Corrective Action and Assessment

W. Brian, General Manager, Plant Operations

M. Krupa, Director, Nuclear Safety Assurance Corrective Action and Assessment

T. Thornton, Manager (Acting), Design Engineering

NRC personnel

A. Barrett, Resident Inspector, Grand Gulf

R. Bywater, Senior Reactor Analyst, Region IV

G. Miller, Senior Resident Inspector, Grand Gulf

G. Replogle, Senior Reactor Inspector, Engineering Branch 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

05000382/2006008-01 NCV Inadequate Test Control Program for Standby Service Water-Cooled Heat Exchangers (Section 1R21b.1.).

05000382/2006008-02 NCV Failure to Translate Design Basis Information into Specifications and Procedures (Section 1R21b.2.).