**ATTACHMENT 71111.08**

INSPECTABLE AREA: Inservice Inspection Activities

CORNERSTONES: Initiating Events (45%)

> Barrier Integrity (45%)
>
> Mitigating Systems (10%)

INSPECTION BASES: Inservice inspection (ISI) activities can detect
precursors to pressure boundary failures in reactor coolant systems
(RCS), emergency core cooling systems (ECCS), risk-significant piping
and components, and containment systems. Degradation of pressure
boundaries of reactor coolant systems, steam generator tubes, emergency
feedwater systems, essential service water systems, and containments
would result in a significant increase in risk. This inspection is
intended to assess the effectiveness of the licensee=s program for
monitoring degradation of vital system boundaries.

> The scope of this inspectable area is limited to the following
> structures, systems, and components (SSCs):

(1) Reactor coolant system pressure boundaries, including steam
    generator tubes in pressurized water reactors (PWRs).

(2) Piping connected to the RCS, failure of which could result in an
    interfacing system loss of coolant accident.

(3) Reactor vessel internals.

(4) Risk-significant piping system boundaries.

(5) Containment system boundaries (including coatings and
    post-tensioning systems, where applicable).

LEVEL OF EFFORT: Inspections are generally to be performed during each
refueling outage at each reactor unit at a site. The level of ISI
activities including steam generator inspections at each plant can vary
significantly from outage to outage but typically should be as
identified in this procedure. Since all activities are subject to outage
availability, inspectors must make a reasonable effort to ensure that
the inspection effort occurs during the time that the activities are
scheduled.

71111.08-01 INSPECTION OBJECTIVE

To assess the effectiveness of the licensee=s program for monitoring
degradation of the reactor coolant system boundary, risk-significant
piping system boundaries, and the containment boundary.

71111.08-02 INSPECTION REQUIREMENTS

02.01 [Non-Destructive Examination (NDE) Activities and Welding
Activities]{.underline}

a.  Review a sample of nondestructive examination (NDE) activities. The
    review sample should consist of two or three types of NDE
    activities, including at least one volumetric examination.

b.  Order of preference for reviewed NDE activities:

    1.  Volumetric examinations

    2.  Surface examinations

    3.  Visual examinations (VT-1 and/or VT-3 on risk significant
        components)

c.  For each examination reviewed, perform the following through either
    direct observation (preferred method) or record review:

    1.  [For ASME Code Required Examinations]{.underline}

        a.  Verify that NDE activities are performed in accordance with
            ASME Boiler and Pressure Vessel Code requirements.

        b.  Verify that indications and defects, if present, are
            dispositioned in accordance with the ASME Code or an NRC
            approved alternative (e.g., approved relief request).

        c.  Verify that relevant indications are compared to previous
            examinations to determine if any changes have occurred.

    2.  [For Other Augmented or Industry Initiative
        Examinations:]{.underline}

        a.  Verify the activities are performed in accordance with the
            licensee=s augmented inspection program and associated
            examination procedure (e.g., examinations of components such
            as vessel internals subject to fatigue, intergranular stress
            corrosion or irradiation assisted stress corrosion,
            feedwater pipe subject to flow-accelerated corrosion, nickel
            based weldments subject to primary water stress corrosion
            cracking etc).

        b.  Verify indications and defects, if present, are
            dispositioned in accordance with licensee=s procedures and
            NRC requirements.

        c.  Verify the activities are performed in accordance with
            applicable industry guidance documents and NRC commitments.
            For deviations with possible safety implications, the
            inspector should inform the applicable NRR branch, so that
            they can consider possible discussion with the applicable
            industry group and provide assistance on whether and how the
            licensee.

d.  If applicable, review at least one volumetric or surface examination
    from the previous outage with relevant indication(s) that were
    analytically evaluated and accepted by the licensee for continued
    service. Verify that the licensee=s acceptance was in accordance
    with the ASME Code or an NRC approved alternative, and confirm the
    indication(s) were examined for acceptability for continued service.

e.  If applicable, for modifications, repairs, or replacements
    consisting of welding on pressure boundary risk significant systems,
    verify for one to three welds that the welding activities, and any
    applicable NDE performed, were performed in accordance with ASME
    Code requirements, or an NRC approved alternative.

02.02 [PWR Vessel Upper Head Penetration (VUHP) Inspection
Activities]{.underline} ***(To be implemented after the completion of TI
2515/150)***

*Section 02.02 is a requirement of the Davis Besse Lesson Learned Task
Force (DBLLTF) No. 3.3.4(3): Develop inspection guidance or revise
existing guidance to ensure that the vessel head penetration (VHP)
nozzles and the reactor pressure vessel (RPV) head area are periodically
reviewed by the NRC during licensee ISI activities.* \[C-1\]

a.  The inspection requirement steps in 02.02 parallel the inspection
    requirement steps in 02.01. The inspection of the licensee=s reactor
    VUHP activities under 02.02.a and b may be considered as satisfying
    the corresponding inspection requirements of 02.01.a and b.

> If the licensee is performing visual examinations, observe portions of
> this examination or review the post examination videotape and
> examination procedures. In particular, review licensee criteria for
> confirming visual examination quality and instructions resolving
> interference or masking issues.
>
> And/or;
>
> If the licensee is performing non-visual nondestructive examination
> (NDE) of the reactor vessel head, review a sample of these
> examinations. In particular, review the NDE examination procedures
> used to confirm that they are consistent with ASME Code examinations
> and that the equipment and calibration requirements (essential
> variables) are consistent with that used in vendor mockup
> demonstrations on simulated or actual cracking.
>
> And
>
> Review the records recording the extent of inspection for each
> penetration nozzle including documents which resolved interference or
> masking issues.

b.  For each NDE activity reviewed, perform the following through either
    direct observation (preferred method) or record review:

    1.  Verify that the activities are performed in accordance with the
        requirements of NRC Order EA-03-009.

    2.  Verify that indications and defects, if detected, were
        dispositioned in accordance with the ASME Code or an NRC
        approved alternative (e.g., approved relief request).

c.  Review one or two examinations with relevant indications that have
    been accepted for continued serviced. Verify that the licensee=s
    acceptance for continued service was in accordance with the ASME
    Code or an NRC approved alternative.

d.  If welding repairs have been completed on upper head penetrations,
    verify for one to three welds that the welding process and welding
    examinations were performed in accordance with ASME Code
    requirements or an NRC approved alternative.

02.03 [Boric Acid Corrosion Control (BACC) Inspection Activities
(PWRs)]{.underline}

*Section 02.03 is a requirement of the Davis Besse Lesson Learned Task
Force (DBLLTF) No. 3.3.2(1): Develop inspection guidance for the
periodic inspection of Pressurized Water Reactors (PWR) plant boric acid
corrosion control programs.* \[C-2\]

a.  Perform an independent review of plant areas that have recently
    received a boric acid walkdown by the licensee, through either
    direct observation (preferred method) or record review. (Reference
    IP 71111.20)

b.  Verify that visual inspections emphasize locations where boric acid
    leaks can cause degradation of safety significant components.

c.  Review one to three engineering evaluations performed for boric acid
    found on RCS piping and components. Also, verify that degraded or
    non-conforming conditions are identified properly in licensee=s
    corrective action system.

d.  Review one to three corrective actions performed for evidence of
    boric acid leaks identified. Confirm that these corrective actions
    were consistent with requirements of the ASME Code and 10 CFR 50,
    Appendix B, Criterion XVI.

02.04 [Steam Generator (SG) Tube Inspection Activities]{.underline}

a.  In-situ Pressure Testing (if performed).

    1.  Assess whether the in-situ screening criteria are in accordance
        with the EPRI Guidelines. In particular, assess whether assumed
        NDE flaw sizing accuracy is consistent with data from the EPRI
        examination technique specification sheet (ETSS) or other
        applicable performance demonstrations.

    2.  Assess whether the appropriate tubes are to be In-situ pressure
        tested (in terms of specific tubes and number of tubes).

    3.  Review plans for and, if practical, observe in-situ pressure
        testing activities and assess whether tubes are in-situ tested
        in accordance with EPRI In-situ Pressure Test Guidelines. Assess
        test records (e.g., pressure versus time traces, pressure
        achieved, and hold times).

    4.  Review in-situ pressure test results for conformance with the
        performance criteria.

b.  Compare the estimated size and number of tube flaws detected during
    the current outage against the previous outage operational
    assessment predictions to assess the licensee=s prediction
    capability.

c.  Confirm that the SG tube eddy current examination (ET) scope and
    expansion criteria meet technical specification (TS) requirements,
    EPRI Guidelines, and commitments made to the NRC.

d.  If the licensee has identified new degradation mechanisms, verify
    that the licensee has fully enveloped the problem in its analysis of
    extended conditions including operating concerns, and has taken
    appropriate corrective actions before plant startup (e.g.,
    additional inspections, in-situ pressure testing, preventive tube
    plugging, etc.).

e.  Confirm that all areas of potential degradation (based on
    site-specific experience and industry experience) are being
    inspected, especially areas which are known to represent potential
    ET challenges (e.g., top-of-tubesheet, tube support plates,
    U-bends).

f.  Confirm that all repair processes being used have been approved for
    use at the site.

g.  Repair Criteria:

    1.  Confirm that the TS repair criteria are being followed.
        Typically, the TS repair limit is 40 percent through wall,
        although most licensees plug (or repair) crack-like indications
        on detection (unless an alternate to the 40% depth based repair
        criteria has been approved for use). This Aplug on detection@
        approach is due to the inability to reliably depth size flaws.

    2.  Determine whether the depth sizing repair criterion (typically
        40 percent through wall) is being applied for indications other
        than wear or axial primary water stress corrosion cracking
        (PWSCC) in dented tube support plate intersections.

h.  If steam generator leakage greater than 3 gallons per day was
    identified during operations or during post-shutdown visual
    inspections of the tubesheet face, assess whether the licensee has
    identified a reasonable cause for this leakage based on inspection
    results. In addition, determine whether corrective actions are
    planned or were taken to address the cause. Additional guidance on
    this issue is available in Part 9900: Technical Guidance, ASteam
    Generator Tube Primary-to-Secondary Leakage.@

i.  Confirm that the ET probes and equipment are qualified for the
    expected types of tube degradation. Assess the site specific
    qualification of one or more techniques (e.g., equipment, data
    quality/noise issues, degradation mode).

j.  If the licensee has identified loose parts or foreign material on
    the secondary side of the steam generator, focus on licensee
    corrective actions in conjunction with step 02.05 below.
    Specifically, confirm that the licensee has taken/planned
    appropriate repairs of affected SG tubes, inspected the secondary
    side of the SG to remove foreign objects (if possible). If the
    foreign objects are inaccessible, determine whether the licensee has
    performed an evaluation of the potential effects of object migration
    and/or tube fretting damage.

k.  Review one to five samples of eddy current data. If adequate
    expertise for this activity does not reside in the regional office,
    the Office of Nuclear Reactor Regulation (NRR) should be contacted
    via telephone call or e-mail to discuss the need for providing this
    resource.

02.05 [Identification and Resolution of Problems]{.underline}. Verify
that the licensee is identifying ISI/SG problems at an appropriate
threshold and entering them in the corrective action program. Determine
whether the licensee=s procedures direct the licensee to perform a root
cause evaluation and take corrective actions when appropriate. For a
selected sample of problems associated with inservice inspection and
steam generator inspection documented by the licensee, verify the
appropriateness of the corrective actions. See Inspection Procedure
71152, AIdentification and Resolution of Problems,@ for additional
guidance. In addition, a licensee=s evaluation of industry operating
experience can be critical. Determine whether licensees are assessing
the applicability of operating experience to their respective plants.

71111.08-03 INSPECTION GUIDANCE

[General Guidance]{.underline}

For PWRs, the effort expended and the level of detail considered in
performing these activities will be determined on the basis of review of
the previous outage summary report, findings from the previous NRC
inspection, and interaction with NRR staff. For inspection planning,
determine where to place the emphasis in regard to non-SG ISI activities
(Sections 02.01 through 02.03) and SG inspection activities within the
estimated resources. Also, note, when applying the requirements of 02.01
through 02.03, if timing does not permit an inspection step to be
performed on an activity occurring in the current outage, the step may
utilize the activity performed during the previous outage. In other
words, these samples may be chosen from current or previous outage.

[Specific Guidance]{.underline}

03.01 [Non-Destructive Examination (NDE) Activities and Welding
Activities]{.underline}

a.  Volumetric examinations provide the greatest amount of information
    when compared to surface and visual examinations. Review a sample of
    nondestructive examination (NDE) activities. The review sample
    should consist of two or three types of NDE activities, including at
    least one volumetric examination. The reviews should be of
    risk-significant welds.

b.  Sections V and XI in the ASME Code provide the requirements/guidance
    for performance of the applicable NDE method, while the acceptance
    criteria are defined in IWX-3000 of Section XI.

c.  ASME Code Section XI, Article IWX-3130 provides the rules for: (1)
    acceptance by analytical evaluation of flaws detected by volumetric
    or surface examinations, without the flaw removal, repair, or
    replacement, and (2) reexamination requirements.

d.  Verify that the NDE procedures used to verify weld acceptance are in
    accordance with ASME Code Section III, V, IX and XI requirements.

e.  For Section XI Code repairs (i.e., welding), observe available
    welding activities and verify they are performed in accordance with
    the specified Welding Procedure Specification (WPS). Confirm that
    the WPS has been appropriately qualified by review of the supporting
    Procedure Qualification Record(s) (PQRs). Verify that the PQR
    incorporates all of the ASME Code Section III and IX required
    variables specified for the particular welding process used.

03.02 [PWR Vessel Upper Head Penetration (VUHP) Inspection
Activities]{.underline} ***(To be implemented after the completion of TI
2515/150)***

As part of the preparation for vessel upper head inspection, the
inspector should consider reviewing NRC Bulletins 2001-01, Bulletin
2002-01, Bulletin 2002-02 and NRC first revised Order EA-03-009. The
inspector should review the licensee responses to the order, requests
for relaxation from the order, and any NRC approved relaxations from the
order.

03.03 [Boric Acid Corrosion Control (BACC) Inspection Activities
(PWRs)]{.underline}

As part of the preparation for inspection of boric acid corrosion
control, the inspector should consider reviewing Generic Letter 88-05
and RIS 2003-13. The inspector should review licensee commitments made
in response to this generic letter. Appendix B provides a list of
typical PWR plant systems containing boric acid.

03.04 [Steam Generator (SG) Tube Inspection Activities]{.underline}.

[General Guidance]{.underline}

Use the factors discussed below to determine the allocation of the
inspection effort for review of the licensee SG inspection activities as
described in 02.04. If none of these factors apply, the minimum
inspection requirement is to complete steps 02.04a., c., d., g.(1), h.,
i., and j. If any of the factors apply, this baseline inspection effort
should include the inspection of all SG activities identified in 02.04.
If the safety significance of the operating experience warrants, then
consider increasing the depth of the baseline SG inspection effort
beyond the maximum estimated resources if recommended by NRR/DCI and
approved by NRR/DIRS/IRIB.

-   SGs with mill-annealed or stress relieved Alloy 600 tubes should
    receive a review as described in this section at least every other
    outage, or more frequently if other factors discussed below apply.
    For SGs with thermally-treated Alloy 600 and thermally-treated Alloy
    690 tubes this review may not be required unless considerable
    inservice time (e.g., \> 9 yrs since beginning commercial operation
    and more than 2 operating cycles since the last NRC inspection of
    the licensee=s SG inspection activities) or other factors discussed
    below apply.

-   Deteriorating SG tube material condition as indicated by new
    degradation mechanism(s), or a large number or significant increase
    in the number of flaws reported by the licensee during the previous
    SG tube examinations. This information can be obtained from the
    licensee=s most recent SG inspection summary report.

-   SG tube performance criteria (i.e., operational leakage, structural
    integrity, or accident leakage) were not met during the previous
    operating cycle.

-   PWRs with a history of primary-to-secondary leakage during the
    previous operating cycle (e.g., \> 3 gallons per day).

-   Reported potential degraded condition (e.g., NRC and industry
    information notices) due to SG design, water chemistry, material
    properties, or newly identified degradation mechanisms.

The inspection should be scheduled towards the end of the SG inspection
activities, if possible, because the licensee performs a significant
number of evaluations (listed in 02.04) at that time.

Attachment A lists specific situations which, if identified by the
inspector, require notification of NRR staff. In addition, the inspector
is encouraged to contact NRR staff to discuss any other situations or
issues that are identified, that are unexpected based on the inspector=s
experience.

Prior to an inspection, and as a part of the preparation for SG tube
inspections, the inspector should contact NRR staff to determine the
existence of issues or concerns that should be considered for review
during the SG tube inspection. The inspector should also consider
reviewing the licensee=s commitments in response to Generic Letters
(GLs) 95-03, 95-05, 97-05, and 97-06 (see References Section 06). In
addition, the inspector should review the licensee=s most recent SG
inspection summary report. The inspector should also consider reviewing
NRC generic communications, such as relevant information notices and
regulatory information summaries. Lastly, the inspector should become
familiar with the industry steam generator program guidelines contained
in Nuclear Energy Institute (NEI) 97-06 and several related Electric
Power Research Institute (EPRI) reports (see References Section 06). The
EPRI guidelines referenced do not constitute NRC requirements or
commitments and technically acceptable alternative methods may be used
by the licensee. Also, the staff has determined that while the
guidelines represent an improvement over practices followed in the past,
use of the guidelines alone does not ensure that the regulations will be
satisfied. However, if the licensee has deviated from the guidelines,
the basis for the deviation should be documented by the licensee.

Periodically, for plants that have SGs with active degradation or other
SG issues, NRR/DCI staff conduct a conference call with the licensee to
discuss SG tube examination activities. If scheduled by NRR/DCI, the
inspector should participate in the conference calls set up between NRC
and licensee staff (as the timing of the call permits), during which
steam generator tube examination activities are discussed. In addition,
the inspector should review summaries from previous similar conference
calls and can obtain these from NRR/DCI staff. The information obtained
during these calls will be beneficial to the inspector for background
information as well as potentially providing direction for inspection
activities.

[Specific Guidance]{.underline}

a.  In-Situ Pressure Testing

    1.  The inpector should review the EPRI Guidelines for in-situ
        screening criteria in order to determine if the licensee=s
        criteria meets that guidance.

    2.  The inspector should review test data to determine if the
        appropriate tube(s) has/have been properly identified for
        in-situ pressure testing.

    3.  The inspector should observe, when possible, the in-situ
        testing. The inspector should review the test procedure. The
        inspector should determine that the test was performed in
        accordance with the procedure and the EPRI In-Situ Pressure Test
        Guidelines.

    4.  The inspector should evaluate the results of the test against
        the performance criteria identified in the test procedure.

b.  The inspector should review the results of the current examinations
    to determine the ability of the licensee to predict future tube
    performance through assessment of previous performance.

c.  The inspector should review the licensee=s examination scope and
    expansion criteria to determine if both meet the technical
    specification requirements, commitments made to the NRC, and the
    EPRI Guidelines.

d.  New degradation mechanisms are identified by the licensee based on a
    comparison of the summary report of the previous outage results to
    the current outage results. The inspector should notify NRR of the
    new mechanism. NRR will assist in evaluation of the corrective
    actions. If the steam generators have been replaced, then the first
    subsequent outage examination results should be compared to the PSI
    data. (Wear indications observed during the first inspection
    following steam generator replacement should not be considered a new
    degradation mechanism unless a large number of indications (greater
    than approximately 100 indications per steam generator) are detected
    or if large through wall extents are observed (greater than 30%
    through-wall).)

e.  Compare the licensee=s SG tube inspection plan scope to the previous
    outage summary report and NRR identified industry issues to verify
    that all areas of potential degradation have been included.

f.  All repair processes being used must be approved. Verify the
    existence of approval(s) in technical specifications, exemption
    requests, or other NRC correspondence.

g.  Confirm, in the absence of Aplug on detection,@ that the licensee
    has depth sizing techniques that provide reasonable estimates of the
    depth of degradation such that the typical TS repair limit of 40
    percent through-wall can be implemented without a loss of tube
    integrity for the period of time between inspections.

> This criteria may be acceptable and in accordance with the licensee=s
> TS, although experience has shown, for example, that many types of
> IGA/SCC cannot be sized with a sufficient degree of accuracy or
> reliability. In addition, this may indicate licensee practices that
> are inconsistent with their response to GL 97-05. If that is the case,
> contact NRR.

h.  It is suggested that the NRC resident inspectors and regional staff
    use an informal screening criteria of 3 gpd or greater for increased
    involvement by NRC headquarters staff when steam generator primary
    to secondary leakage is identified. This is not meant to be an
    absolute threshold, or requirement, because there may be certain
    instances where there is something unusual about the circumstances
    of the leakage, or other reason that the region would want
    involvement by the headquarters staff before leakage reaches 3 gpd.
    If a licensee reports levels of primary-to-secondary leakage
    exceeding 3 gpd to the resident inspector or regional staff, Office
    of Nuclear Reactor Regulation (NRR) should be informed through the
    morning phone calls. The following section discusses some of the
    typical questions that inspectors can pursue with the licensee when
    leakage is reported.

> When leakage exceeds 3 gpd, parameters that can be considered are the
> effectiveness of licensee procedures, equipment, and practices for
> monitoring and responding to primary-to-secondary leakage. For
> example, the adequacy of procedures and equipment to provide real-time
> information on leak rate and its rate of change could be assessed. The
> appropriate setting of alarm setpoints on those radiation monitors
> that are used for detecting primary-to-secondary leakage (e.g.,
> condenser air ejector, N-16) to alert operators to any increasing leak
> rate could be assessed. In addition, the adequacy of emergency
> operating procedures, availability of systems and components, and
> operator training for response to steam generator tube ruptures could
> also be assessed.
>
> The NRR staff often receives notification of extremely low levels of
> leakage (\< 1 gpd), but these levels of leakage don=t typically need
> to result in increased interaction with the licensee. This is because
> many plants have experienced this level of leakage during a full
> cycle, and it=s difficult to definitively determine the source of the
> leakage at that level. Often, small levels of leakage will persist for
> the rest of the operating cycle for some plants.

i.  Review the equipment and probes used for the examination(s). For
    example, review the test configuration (i.e., frequency, coil
    selection, probe drive, and physical limitations). Verify that the
    appropriate ET probe (e.g., bobbin, pancake, or multi-coil type) is
    used to detect the type of flaw that might be expected. Verify that
    the equipment has been calibrated in accordance with the ET
    procedure(s) and ASME Code.

j.  No specific guidance.

k.  No specific guidance.

03.05 [No specific guidance]{.underline}.

71111.08-04 RESOURCE ESTIMATE

This inspection procedure is estimated to take, on the average, 16 to 32
hours for each BWR unit, and 80 to 100 hours per PWR unit, respectively,
every refueling outage.

Depending on availability, resident staff members may assist the
regional ISI inspectors in completing section 02.03, Boric Acid
Corrosion Control (BACC) Inspection Activities (PWRs).

71111.08-05 COMPLETION STATUS

Inspection of the minimum sample size will constitute completion of this
procedure in the Reactor Program System (RPS). The minimum sample size
will consist of 1sample for each refueling outage at the facility. The
sample for BWR=s consists of all the requirements in Section 02.01, if
available. The sample for PWRs consists of all the requirements in
sections 02.01, 02.02, 02.03, and 02.04, if available.

If a particular activity is not completed because the licensee was not
scheduled to perform this activity in the refuel outage, then document
this in the inspection report. However the sample should be reported as
complete. For example section 02.04 specifies many activities. If one
activity is not completed in section 02.04 because it is not available,
then document the sample as complete.

71111.08-06 REFERENCES

ASME Boiler and Pressure Vessel Code Sections III, V, IX, and XI.

Plant-specific ISI program.

GL 88-05, ABoric Acid Corrosion of Carbon Steel Reactor Pressure
Boundary Components in PWR Plants.@

GL 95-03, ACircumferential Cracking of Steam Generator Tubes.@

GL 95-05, AVoltage-Based Repair Criteria for Westinghouse Steam
Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking.@

GL 97-05, ASteam Generator Tube Inspection Techniques.@

GL 97-06, ADegradation of steam Generator Internals.@

GL 2004-01, ARequirements for Steam Generator Tube Inspections.@

GL 2006-01, ASteam Generator Tube Integrity and Associated Technical
Specifications.@

NRC Bulletin 2002-01, AReactor Pressure Vessel Head Degradation and
Reactor Pressure Boundary Integrity.@

NRC Bulletin 2003-02, ALeakage From Reactor Pressure Vessel Lower Head
Penetrations and Reactor Coolant Pressure Boundary Integrity.@

NEI 97-06, ASteam Generator Program Guidelines.@

APWR Steam Generator Examination Guidelines,@ EPRI Report TR-107569.

ASteam Generator Integrity Assessment Guidelines,@ EPRI Report
TR-107621.

ASteam Generator In Situ Pressure Test Guidelines,@ EPRI Report
TR-107620.

Inspection Procedure 71152, AIdentification and Resolution of Problems.@

Inspection Procedure 71111.20, ARefueling and Other Outage Activities@.

Part 9900: Technical Guidance, ASteam Generator Tube
Primary-to-Secondary Leakage.@

First Revised Order, EA-03-009, AIssuance of Order Establishing Interim
Inspection Requirements for Reactor Pressure Vessel Heads at Pressurized
Water Reactors,@ February 20, 2004.

RIS 2003-13, ANRC Review of Responses to Bulletin 2002-01, AReactor
Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary
Integrity.@A

WCAP-15988-NP, AGeneric Guidance for an Effective Boric Acid Inspection
Program for Pressurized Water Reactors,@ Revision 1 April 2005 (ADAMS
Accession No.ML050960532).

NRC Regulatory Issue Sumary (RIS) 2007-20, Implementation Of Primary-To-
Secondary Leakage Performance Criteria.

END

**APPENDIX A**

**Tube Integrity Issues Requiring Further Evaluation by NRR Staff**

If the following situations are identified by the inspector,
NRR/Division of Component Integrity (DCI) staff should be promptly
contacted. NRR/DCI staff will determine whether NRR involvement is
necessary. In addition, the inspector is encouraged to contact NRR/DCI
staff to discuss any other situations or issues that are identified,
that are unexpected based on the inspector=s experience.

> 1\. Selection of tubes to be in-situ pressure tested is not consistent
> with EPRI guidance (i.e., number of tubes to be tested, or specific
> tubes to be tested, or NDE uncertainty is not consistent with data
> from the EPRI examination technique specification sheet (ETSS) or
> other applicable performance demonstrations).
>
> 2\. In-situ pressure testing of flawed tubes is not successful in
> reaching the desired test pressure (e.g., main steam line break for
> accident induced leakage, 3 times normal operating differential
> pressure and 1.4 times main steam line break pressure for burst),
> either due to tube failure/leakage or equipment problems/limitations.
>
> 3\. Estimated size or number of tube flaws detected during the current
> outage invalidates bounding assumptions from the previous outage
> operational assessment predictions.
>
> 4\. If the licensee=s use of depth sizing is inconsistent with their
> response to NRC Generic Letter 97-05.
>
> 5\. A tube repair criteria or repair process is being used which has
> not been reviewed by the NRC for use at this site (e.g., alternate
> tube repair criteria, or sleeving process).
>
> 6\. If tube inspections or testing do not identify the source of
> primary-to-secondary leakage observed during the previous operating
> cycle or during post-shutdown visual inspections of the tubesheet
> face.

ATTACHMENT 1

REVISION HISTORY FOR IP 71111.08

+--------+--------+-----------+---------+-------------+----------------+
| Comm   | Issue  | De        | T       | Training    | Comment        |
| itment | Date   | scription | raining | Completion  | Resolution     |
| Tr     |        | of Change | Needed  | Date        | Accession      |
| acking |        |           |         |             | Number         |
| Number |        |           |         |             |                |
+--------+--------+-----------+---------+-------------+----------------+
| C-1    |        | Revision  | No      | N/A         | N/A            |
|        |        | History   |         |             |                |
| Refe   |        | Reviewed  |         |             |                |
| rence: |        | for last  |         |             |                |
|        |        | four      |         |             |                |
| DBLLTF |        | years.    |         |             |                |
|        |        |           |         |             |                |
| 3.     |        | Develop   |         |             |                |
| 3.4(3) |        | I         |         |             |                |
|        |        | nspection |         |             |                |
|        |        | Guidance  |         |             |                |
|        |        | for       |         |             |                |
|        |        | Vessel    |         |             |                |
|        |        | Head      |         |             |                |
|        |        | Pen       |         |             |                |
|        |        | etrations |         |             |                |
|        |        | and RPV   |         |             |                |
|        |        | Head Area |         |             |                |
|        |        | Ins       |         |             |                |
|        |        | pections. |         |             |                |
+--------+--------+-----------+---------+-------------+----------------+
| C-2    |        | Revision  | No      | N/A         | N/A            |
|        |        | history   |         |             |                |
| Refe   |        | reviewed  |         |             |                |
| rence: |        | for last  |         |             |                |
|        |        | four      |         |             |                |
| DBLLTF |        | years.    |         |             |                |
|        |        |           |         |             |                |
| 3.     |        | Develop   |         |             |                |
| 3.2(1) |        | I         |         |             |                |
|        |        | nspection |         |             |                |
|        |        | Guidance  |         |             |                |
|        |        | For Boric |         |             |                |
|        |        | Acid      |         |             |                |
|        |        | Corrosion |         |             |                |
|        |        | Control   |         |             |                |
|        |        | Programs. |         |             |                |
+--------+--------+-----------+---------+-------------+----------------+
| None   | 10     | IP        | No      | N/A         | ML072400349    |
|        | /04/07 | 71111.08  |         |             |                |
|        |        | has been  |         |             |                |
|        | CN     | revised   |         |             |                |
|        | 07-031 | to        |         |             |                |
|        |        | in        |         |             |                |
|        |        | corporate |         |             |                |
|        |        | best      |         |             |                |
|        |        | practices |         |             |                |
|        |        | of ISI    |         |             |                |
|        |        | working   |         |             |                |
|        |        | group.    |         |             |                |
+--------+--------+-----------+---------+-------------+----------------+