ML13030A462

SCE Brief on Issues Referred by the Commission, Attachments 12 - 24

ML13030A462
Person / Time
Site:	San Onofre
Issue date:	01/30/2013
From:	Southern California Edison Co
To:	Atomic Safety and Licensing Board Panel
SECY RAS
Shared Package
ML130310300	List: ML13030A441 ML13030A451 ML13030A456 ML13030A462 ML13030A467
References
RAS 24061, 50-361-CAL, 50-362-CAL, ASBLP 13-924-01-CAL-BD01
Download: ML13030A462 (250)

Text

SCE ATTACHMENT 12 SOUTHERN CALIFORNIA JEDISON

,\n EDIS*O;N I:VT'IE,N 110 \ALI0 Company SONGS Unit 2 Return to Service Report ATTACHMENT 6- Appendix B SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear

[Proprietary Information Redacted]

A Document No.: 51-9187230-000 (NP)

AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear Table of Contents Page SIGNATURE BLOCK ................................................................................................................................ 2 RECORD OF REVISION ......................................................................................................................... 3 LIST OF FIG URES ................................................................................................................................... 6 LIST OF ABBREVIATIONS .................................................................................................................... 10 1.0 PURPOSE ................................................................................................................................... 12

2.0 BACKGROUND

.......................................................................................................................... 12

3.0 INTRODUCTION

......................................................................................................................... 15 4.0 OPERATIONAL ASSESSM ENT STRATEGY ........................................................................ 16 4.1 Development of TTW ................................................................................................. 16 4.2 Operational Assessment Strategy ............................................................................... 20 5.0 STABILITY RATIOS .................................................................................................................... 43 6.0 CONTACT FORCES ................................................................................................................... 56 6.1 MHI Quarter Bundle Steam Generator Model ............................................................ 56 6.2 Contact Force Distributions - Unit 3 .......................................................................... 57 6.3 Contact Force Distributions - Unit 2 .......................................................................... 59 6.4 Dent Evaluation ........................................................................................................... 59 6.4.1 Pre-Service Dents ...................................................................................... 59 6.4.2 Non-Classical Dents ................................................................................. 60 6.5 Tube-to-AVB Gap Evaluation ...................................................................................... 61 6.5.1 Unit 2 Tube-to-AVB Gaps .......................................................................... 62 6.5.2 Effect of Gap Size on Tube-to-AVB Wear ................................................. 62 6.5.3 Unit 3 Tube-to-AVB Gaps .......................................................................... 62 6.6 Conclusions - Contact Forces ................................................................................... 63 7.0 CRITERIA FOR EFFECTIVE VERSUS INEFFECTIVE SUPPORTS .................................... 97 7.1 Equal Contact Force at Each AVB ............................................................................ 97 7.2 Variable Contact Force at Each AVB .......................................................................... 97 7.3 Single AVB Effective (Upper Bound Contact Force) .................................................. 98 7.4 Chosen Approach for the OA ...................................................................................... 98 7.5 Sum mary - Criteria for Support Effectiveness ............................................................ 99 Page 4 of 129 Page 4 1814-AU651-M0160, REV. 0

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear Table of Contents (continued)

Page 8.0 PROBABILITY OF INSTABILITY RESULTS ............................................................................ 104 9.0 D E F E N S E-IN -D E P T H ............................................................................................................... 113 10 .0 C O N C LUS IO N S ........................................................................................................................ 1 17 1 1.0 R E F E R E NC E S .......................................................................................................................... 1 18 APPENDIX A: ESTIMATES OF FEI-INDUCED TTW RATES ....................................................................... A-1 Page 5 1814-AUb51-1VlU1bU, Kt . U P'age 0 O oI ZV

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear

3.0 INTRODUCTION

During the U2C17 outage, SONGS Unit 3 was shut down due to a primary-to-secondary leak. Eddy current inspections of the Unit 3 steam generators revealed that the cause of the leak was tube-to-tube wear (TTW) in the U-bend region of a cluster of tubes located near the center of the tube bundle. Based on a root cause evaluation performed by SCE [11], the TTW in the SONGS steam generators was caused by in-plane tube movement due to in-plane fluid-elastic instability (FEI).

No indications of TTW were reported during the initial U2C17 inspections of the Unit 2 steam generators, which included full-length eddy current inspections of all tubes with bobbin coil probes. However, since 823 indications of TTW were detected in the SONGS-3 steam generators [12] and the design of the SONGS-3 steam generators is the same as the SONGS-2 steam generators, supplemental +PointTM inspections of the U-bends were performed in SONGS-2. These supplemental inspections included the full-length of the U-bend for a group of tubes in the same region as those with TTW in Unit 3. These supplemental inspections resulted in the finding of two adjacent tubes with shallow TTW in SG E-089 of Unit 2. According to Reference [12], the wear depth was reported to be 14%

through-wall (TW) based on EPRI Examination Technique Specification Sheet (ETSS) 27902.2. ETSS 27902.2 was developed for freespan wear caused by loose parts; this technique overestimates the depth of TTW and therefore results in a conservative measurement for purposes of assessing tube integrity. However it is more appropriate to base the engineering assessments in this OA on the best estimate of the wear depth. For this reason the tubes were re-sized using a site-specific ECT calibration standard developed for TTW. The tubes were also re-inspected using an ultrasonic (UT) technique. Both of these techniques resulted in an indicated TTW depth of 7% TW. The assessments in this OA are appropriately based on the 7% TW depth measurement from UT which is considered a more accurate measure of the true depth.

Tube wear at support locations (AVB and TSP) detected in Unit 2 is within previous industry experience and can be evaluated using standard practices as described in the EPRI Tube Integrity Assessment Guidelines [2]. These degradation mechanisms are not threatening in Unit 2, as demonstrated by Reference [6], which justified a full cycle of operation at full reactor power. However, given identical designs, Unit 2 must be judged, a priori, as susceptible to the same TTW degradation mechanism as Unit 3 where 8 tubes failed structural integrity requirements after 11 months of operation [12]. Indeed, the location and orientation of the two shallow TTW indications in Unit 2 are consistent with the behavior observed in Unit 3 and indicates that in-plane fluid-elastic instability in Unit 2 began shortly before the end of cycle 16 operation after 22 months of operation. It should be noted that this statement is contested by a viewpoint that TTW in Unit 2 is simply a consequence of tubes being in very close proximity to one another with self-limiting wear produced by a combination of turbulence and out-of-plane fluid-elastic excitation. This viewpoint has been evaluated completely and is considered to be arguable but not definitive. The argument that incipient in-plane fluid-elastic has developed in Unit 2 is considered a more logical explanation for the observed TTW but again cannot be stated as definitive. It is ultimately a moot point since the observations in Unit 3 make TTW via in-plane fluid-elastic instability a potential degradation mechanism for Unit 2. The severity of potential degradation via this mechanism dictates that it must be evaluated in a thorough manner both as a matter of logic and by the requirements of NEI 97-06 [5] and the EPRI Tube Integrity Assessment Guidelines [2]. Based on the extremely comprehensive evaluation of both Units, supplemented by thermal hydraulic and FIV analysis, assuming, a priori, that TTW via in-plane fluid-elastic instability cannot develop in Unit 2 would be inappropriate.

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AR EVA SONGS U2C1 7 Steam Generator Operational Assessment for Tube-to-Tube Wear 4.0 OPERATIONAL ASSESSMENT STRATEGY Understanding the TTW phenomena observed in Unit 3 is key to developing a rational operational assessment strategy for Unit 2. Extensive analysis has led to a good understanding of how and why TTW developed in both Unit 3 and Unit 2. This is summarized in Section 4.1. The operational assessment strategy is then presented in Section 4.2.

4.1 Development of TTW Both steam generators in Unit 3 had more than 160 tubes with TTW indications in U-bends. The three most degraded tubes exhibited wear scars that were more than 28 inches long with central regions of essentially uniform wear depths that were greater than 80 %TW. These central regions of uniform wear depth were about 5 inches long. One of these regions contained a pinhole wall penetration that led to a small primary-to-secondary leak, resulting in the shutdown of Unit 3. Figure 4-1 shows the profile of wear depth versus axial length for the leaking tube, RI06 C78, in Unit 3 SG E-088.

TTW scars are located on the extrados and intrados locations of U-bends. Wear scars on extrados locations of a given U-bend have matching wear scars on intrados locations of the neighboring row tube in the same column.

The matching wear scars have very similar depths of wear [13]. The nominal distance between extrados and intrados locations of neighboring U-bends in the same plane ranges from 0.25 inches to 0.325 inches due to the tube indexing, as mentioned earlier. There are instances where the closest approach distance is less than this value based on field measurements using bobbin coil ECT. The bobbin probe on the 140 kHz absolute channel can detect neighboring U-bends if the separation distance is less than approximately 0.15 inches. Using a proximity signal calibration curve, the separation distance between U-bends was measured for all steam generators. The results of these measurements are reported in Reference [14]. The smallest detected U-bend separation distance is close to contact. There are 36 U-bends in Unit 2 SG E-088 and 34 in SG E-089 with a separation less than or equal to 0.050 inches. The separation of the U-bends in Unit 2 with TTW is 0.190 inches as measured by UT. The U-bends with the smaller separation distances are much better candidates for wear by rubbing yet do not exhibit TTW. In Unit 3, TTW via in-plane fluid-elastic instability is incontrovertible based on evidence presented in the following paragraphs.

An SCE root cause analysis [11] has identified in-plane fluid-elastic instability as the mechanistic cause of TTW in the SONGS steam generators. Out-of-plane fluid-elastic instability has been observed in nuclear steam generators in the past and has led to tube bursts at normal operating conditions. However, the observation of in-plane fluid-elastic instability in steam generators in a nuclear power plant is a true paradigm shift. It is not uncommon for designers of nuclear steam generators to calculate that large U-bends supported only by lateral AVB's are fluid elastically unstable in the in-plane direction under the assumption of no effective in-plane supports. This is textbook knowledge and part of the technical literature.

The caption of Figure 4-2, taken from a book by M. K. Au-Yang that was published in 2001 [15], reads, "In-plane modes that have never been observed to be unstable even though the computed fluid-elastic stability margins are well below 1". The fluid-elastic stability margin, FSM, is the inverse of the stability ratio, SR1. An FSM well below 1 means an SR well above 1 and well into the unstable range. As an example of the extensive laboratory 1Stability ratio is defined as the ratio of the effective flow velocity to which the tube is subjected to the critical velocity. Critical velocity is the velocity at which the tube, with specific geometry and support conditions, becomes unstable. Stability ratios less than 1.0 represent a stable condition where the actual velocity is less than the critical velocity; stability ratios greater than 1.0 represent an unstable condition where the actual velocity exceeds the critical velocity.

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear testing campaigns conducted to detect in-plane fluid-elastic instability, Weaver and Schneider [16], in 1983, examined the flow induced response of heat exchanger U-tubes with flat bar supports. It is worth quoting the first conclusion of their paper:

"The effect of flat bar supports with small clearance is to act as apparent nodal points for flow-induced tube response. They not only prevented the out-of-plane mode as expected but also the in-plane modes.

No in-plane instabilities were observed, even when the flow velocity was increased to three times that expected to cause instability in the apparently unsupported first in-plane mode."

Additionally, in an effort to encourage the development of in-plane instability, Weaver and Schneider [16]

substantially increased the clearances between flat bar supports and U-tubes, but no in-plane instability was observed. Other investigators, notably Westinghouse, have deliberately searched for in-plane instability with only support from flat bars and have not detected the phenomena. However in 2005, Janzen, Hagburg, Pettigrew and Taylor [17] reported in-plane instability. The abstract to their paper states, "For the first time in a U-bend tube bundle with liquid or two-phase flow, instability was observed in both the out-of-plane and in-plane direction." The test setup included tubes with a U-bend radius of 0.646 m (25.4 in.) with flat bar U-bend restraints inserted between columns at the apex of the U-bend. The bundle was subjected to air-water cross-flow directed at the mid-span between the 00 and 900 location (apex) of the bundle. Tube vibration was measured over a range of void fractions and flow rates, and for three tube-to-support diametral clearances: no support, 1.5 mm (59 mil) and 0.75 mm (30 mil). It is noted that these test clearances are significantly larger than the SONGS steam generator design clearance of 2 mils diametral.

Prior to the observations at SONGS Unit 3, no in-plane instability had been observed in any U-bend nuclear steam generator. The service history of U-bends with flat bar supports had been successful up to this point. This includes depending on in-plane effectiveness of flat bar supports to demonstrate relatively low values of stability ratios. Stability depends on both thermal-hydraulic flow conditions and in-plane support effectiveness. Logically either or both of these factors are causing the observed instability in SONGS Unit 3. From an overall engineering perspective it is worth considering an operational envelope that is the set of past design and operational factors that have led to successful performance. One technique for doing so is a spider diagram where many factors for different plants and designs are considered by plotting of relative ranking on axes arranged in a star pattern.

Connecting the dots from one axis to another for a given plant creates a periphery that defines the operational parameters for that plant. The outer boundary of all these peripheries of past successful performance is the successful operational envelope.

It should be recognized that the goal of efficient and optimized design leads to expansion of the operational envelope over time and this has occurred in the past. Using data from [18], a spider diagram is presented in Figure 4-3. More parameters are needed to completely define all parameters that have an influence on in-plane FEI, for example some measure of support effectiveness. This could be something as specific as design clearances or as general as the ratio of the total support structure weight to the weight of supported U-bends. The two axes of Figure 4-3 with plotted data are bulk velocity ratio and mean void fraction ratio, which are those parameters that are publically available. High velocities increase susceptibility to instability and a high void fraction indicates lower damping and thus less resistance to instability. At 100% power, the thennal-hydraulic conditions in the u-bend region of the SONGS replacement steam generators exceed the past successful operational envelope for U-bend nuclear steam generators based on presently available data. The operational envelope will be reconsidered in Section 7.0 in the context of a lower power level (see also Figure 5-1). The service performance of SONGS Unit 3 at 100% power shows that there is a boundary to the successful operational envelope.

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear The following paragraphs discuss inspection results and their consistency with in-plane fluid-elastic instability.

This provides the background needed to develop an operational assessment strategy.

Figure 4-4 and Figure 4-5 are tubesheet maps illustrating the U-bends in Unit 3 SG E-088 and SG E-089 that have TTW. The more detailed view of the positions of TTW indications in Figure 4-6, Figure 4-7 and Figure 4-8 are instructive. Note that the positions are contiguous with only one tube not affected. This argues against a random spatial and temporal occurrence of instability. There just aren't enough unaffected tubes to indicate that instability independently initiated at different positions at different times. Three dimensional plots of TTW depth versus column and row in Figure 4-9 and Figure 4-10 reinforce the concept that the development of instability at different positions is a sequence of dependent events and not a sequence of independent events. The plot of wear depths resembles a mound with the largest depths at the top and then sloping to lower values in all directions.

This is also illustrated by the color coded depths in Figure 4-4 and Figure 4-5. The two U-bends in Unit 2 SG E-089 with shallow TTW indications are plotted as red points in Figure 4-8 to illustrate their position in the bundle for comparison with Unit 3.

TTW due to in-plane fluid-elastic instability is a unique degradation mechanism because one unstable tube can drive its neighbor to instability through repeated impact events. Repeated impacts move the neighbor tube relative to its AVBs causing accelerated wear and elongated wear. The in-plane effectiveness of the AVBs is degraded and an initially stable neighbor tube eventually becomes unstable. This leads to a growing region of instability and TTW. Impact events lead to the propagation of instability from one tube to another in the same column. Propagation of instability from one column to another must involve fluid coupling since tube-to-tube impact does not occur across columns. Fluid coupling is discussed in Reference [19]. The two basic theories of fluid-elastic instability have been termed fluid stiffness and fluid damping. With fluid damping perturbations/hysteresis effects in flow fields can lead to negative damping and thus lead to instability. Given the large displacements involved with instability and TTW, the fluid coupling argument is undeniably reasonable.

The extent of movement of unstable tubes, as well as tubes being driven to instability by impact from unstable tubes, is revealed by elongated wear scars at some AVB locations. Typically, turbulence induced wear leads to wear scars with a length equal to or less than the width of an AVB.

Figure 4-11 and Figure 4-12 show that the Unit 3 elongated wear scars only occur within the region of unstable tubes with TTW. In these figures elongated wear scars are identified by comparing a bobbin probe evaluation of AVB width with a +PtTM probe evaluation of wear scar length. More complete results, based only on a bobbin probe evaluation of wear scar lengths, are shown in Figure 4-13 and Figure 4-14. Outside of the region of TTW the length of wear scars at AVB locations returns to normally expected values. It should be noted that because of field spread effects the bobbin probe typically overestimates wear scar lengths. Even though no evidence of elongated wear scars is evident in Unit 2, it doesn't necessarily rule out undetected in-plane instability. Wear scars at AVB locations may be too shallow to evaluate properly and AVB wear scar lengths may be shortened by a contact length that is small because of the presence of AVB twist. The best evidence of in-plane instability is the detection of TTW, not the detection of elongated AVB wear scars. Extensive inspections of the regions of interest with the +PtTM probe show that possible undetected TTW would be less than 5 %TW. It is unreasonable to expect detectable elongation of AVB wear scars without the detection of TTW. The significance of elongated AVB wear scars is that the amount of elongation reveals the extent of unstable tube motion in-plane.

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-- ' J MHI Poprietar -

When the displacement of the unstable tube in a direction perpendicular to the U-bend exceeds the local tube-to-tube spacing, it will impact the neighboring tube. By plotting the radially outward displacement versus angle around the U-bend, the points of impact with a neighboring tube can be determined. For Mode I displacements in the tubes of interest, the centers of impact with a neighbor tube are at 480 and 1320 as measured from the positive x axis. The numbering sequence used to identify AVBs corresponds to 132' being on the hot leg and 480 being on the cold leg of the U-bends. Depth versus length profiles were determined for 777 separate TTW indications in Unit 3 with almost all containing some central region with an essentially uniform maximum depth. The center of impact was considered to be at the midpoint of this central region of maximum depth. Figure 4-17 shows a plot of impact locations compared to locations consistent with Mode 1, Mode 2 and Mode 3 displacement patterns. The impact points are overwhelmingly consistent with Mode I displacements. Parenthetically, the two TTW scars in Unit 2 are at 480, the Mode I impact point. Mode I is the lowest natural frequency of in-plane U-bend vibration and thus is the first mode to be excited to instability. Mode 2 and Mode 3 displacements are shown in Figure 4-18 and Figure 4-19, respectively. Note that only one half of the cycle is illustrated in all modal displacement plots. The other half of the cycle produces displacements that are exactly opposite of those shown.

A tube subject to FEI in the in-plane direction can move in different modes, as shown in Figure 4-15, Figure 4-18 and Figure 4-19. Note that some impact points shown in Figure 4-17 are consistent with Mode 2 and Mode 3 displacement patterns. There are three possibilities for the appearance of these locations: excitation of instability in Modes 2 and 3, excitation of other vibration patterns due to initial Mode I impact events, or excitation of Mode 2 and Mode 3 vibration due to a momentarily strong interaction of an unstable tube in Mode 1 with an AVB as it passes that AVB. It is likely that some combination of these conditions is operative, but this cannot be conclusively determined by analysis.

The mechanisms and forces involved in fluid-elastic instability in tube bundles are presented later in this section.

For the present, it is sufficient to note that the forces at AVB locations needed to prevent the onset of fluid-elastic instability are low. In contrast, after instability develops, the amplitude of in-plane motion continuously increases and the forces needed to prevent in-plane motion at any given AVB location become relatively large. Hence shortly after instability occurs, U-bends begin to swing in Mode 1 and overcome hindrance at any AVB location.

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-ep- Plant E Parameter D ParameterC Figure 4-3: Spider Diagram of the Operational Envelope for Large U-bend Steam Generators Page 25

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear 5.0 STABILITY RATIOS An extensive effort was devoted to defining and refining the basis for the calculation of stability ratios.

Calculation procedures and results are described in [20]. These results compare very well with independent calculations performed by Westinghouse [21]. It is important to state that stability ratio results are reported for the following conditions:

• 100% Power with an Upper 9 5 th Percentile Stability Ratio 0 70% Power with an Upper 95th Percentile Stability Ratio

• 100% Power with an Upper 9 9 th Percentile Stability Ratio

• 70% Power with an Upper 9 9 th Percentile Stability Ratio Basic conclusions regarding stability of U-bends at SONGS are based on the 9 5 th percentile stability ratios. The more conservative 99b percentile ratios are presented only to demonstrate margin and degree of conservatism.

The same holds true for references to instability developing at a stability ratio of I or more in contrast to maintaining a maximum stability ratio of 0.75. Again this later value is discussed in terms of margin and degree of conservatism.

Before beginning the discussion of the effect of power level on in-plane fluid-elastic stability, a more general engineering observation is pertinent. A decrease to 70% power places the SONGS steam generators back inside the operational envelope of demonstrated successful performance relative to in-plane fluid-elastic stability of nuclear steam generators with large U-bends. This is illustrated in Figure 5-1.

A stability ratio is a calculated value which depends on several inputs. A calculation of burst pressure of a degraded tube is exactly analogous. Uncertainties in input values lead to uncertainties in the output calculation.

When all inputs are at mean values, a mean value of the output parameter is obtained. [

As previously stated, stability ratios depend on U-bend size, thermal-hydraulic conditions along the U-bend and the number of consecutive ineffective in-plane supports. Hence, stability ratios vary with position in the bundle and with the number of consecutive ineffective supports. This information is presented by means of a color coded tubesheet map, which was created by calculating stability ratios at 316 different locations and then interpolating between tube positions to develop a stability ratio for each tube. Figure 5-3 denotes the number of consecutive ineffective supports in-plane by color coding stability ratios equal to or greater than I for the SONGS-2 steam generators at 100% power and the no plugging condition at the beginning of life. At low rows, no in-plane supports are needed to maintain tube stability; therefore they have no effect on the probability calculations. In the highest susceptibility regions, instability is predicted if there are 5 consecutive ineffective supports. A decrease to 70% power produces dramatic effects; no in-plane effective supports are needed to maintain a stability ratio less

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AR EVA SONGS U2C1 7 Steam Generator Operational Assessment for Tube-to-Tube Wear than 1, and as a result, the tubesheet map for instability is a blank sheet as shown in Figure 5-4. Thus demonstration of stability at 70% power is an appropriate basis for Unit 2 return to service.

There are two additional important considerations included in the 70% power result which are specific to Unit 2.

Based on the measured wear at AVB locations, the comparisons with Unit 3 AVB wear patterns and the elevated risk of susceptibility to in-plane fluid-elastic instability, Unit 2 tubes will be plugged. These plugged tubes have an effect on local thermal-hydraulic conditions upon returning the SG to operation and have been included in the stability ratio calculations. [

] Rl 13 C81 is shown because it has slightly higher computed stability ratios than does R I II C81.

Stability ratio varies with amplitude as shown. All stability ratios are less than 1.0, assuming zero effective AVBs.

The remaining paragraphs of this section deal with margin, sensitivity and degree of conservatism arguments.

These are necessary elements of a complete evaluation of in-plane fluid-elastic stability. [

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear 8.0 PROBABILITY OF INSTABILITY RESULTS The material presented in Section 5.0 on stability ratios demonstrated that all tubes are stable (SR < 1) at 70%

power with a probability of 0.95 at 50% confidence without any effective in-plane supports. No TTW will develop and thus the operational assessment goal of meeting structural and leakage integrity requirements with 0.95 probability at 50% confidence is met. Probability of instability calculations are used only to demonstrate margin. The desired margin is a projected maximum stability ratio of 0.75 with 0.95 probability at 50%

confidence over the next inspection interval of 5 months. Some effective in-plane supports are needed to maintain a stability ratio of 0.75. In the most limiting case, 4 effective supports are required. This requirement applies to approximately 120 U-bends. See Figure 5-10. Note that all U-bends are considered in probability calculations, including plugged tubes with split stabilizers inserted.

Wear at AVB locations will degrade in-plane support effectiveness over time. The essentially stable behavior of Unit 2, with only two tubes arguably unstable at 100% power at EOC 16, shows that no more than 5 supports were ineffective (Figure 5-6). Immediately after restart at 70% power, stability ratios less than 0.75 are expected.

The question of interest is the length of operating time it takes for wear at AVBs to degrade support effectiveness to the point where the probability of a maximum stability ratio of 0.75 is greater than 0.05. The following paragraphs describe the procedure for calculating the probability of instability.

As noted earlier, calculations of the probability of instability is straightforward in principle. The development of in-plane fluid-elastic instability of U-bends depends on four factors. These are:

" Location in the bundle

• Operating power level

• Number of consecutive ineffective supports

" Operating time These factors affect stability ratios. Support effectiveness in-plane is defined in terms of contact forces at AVB locations. The number of consecutive ineffective supports can change over time as AVB wear reduces contact forces. Descriptions of stability ratios, contact forces at AVB locations and criteria for determining support effectiveness are provided in previous sections. This is the information required to compute the likelihood of encountering in-plane fluid-elastic instability at a given power level as a function of operating time.

The probability of instability is computed using a Monte Carlo approach. One Monte Carlo trial of all tubes in a steam generator is constructed in the following manner:

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7. Whether or not the steam generator contains any unstable U-bend in one Monte Carlo trial of the steam generator is recorded.

8. Typically 10,000 Monte Carlo trials of a steam generator are performed. In this case the probability of instability is simply the number of trials where the steam generator contained one or more unstable tubes divided by 10,000.

Several independent programs use mathematically equivalent algorithms to compute the probability of instability.

In this case, probability calculations were performed using [ ] [27]. Independent checks of test cases were performed to verify the methodology using an independent [

I Figure 8-1 illustrates the first step in constructing one Monte Carlo trial for a full bundle. The cumulative distribution, CDF, of contact forces for a given AVB location at a given position in the bundle is examined. If a single contact force for support effectiveness is used, for example [ ] , the value of the CDF curve at [ J provides the probability that the support will be ineffective. This is true because the value of the CDF curve at

[ ] is the fraction of the total population of contact forces that are equal to or less than 3N. In this case, the support is considered effective if the contact force is any value greater than [ ] . The value of the CDF curve at [ ] is termed the probability threshold for support ineffectiveness. Support effectiveness for a given AVB on a given tube is determined by selecting a random number from a uniform distribution from 0 to I. If this value is above the probability threshold for support ineffectiveness the support is effective. If it is equal to or below the threshold, the support is ineffective.

The above is an example of a single parameter criterion for support effectiveness. [

I The first step is the crucial step in the Monte Carlo trial. It is repeated for all AVB locations in a particular U-bend. [

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear Before proceeding to probability of instability results for Units 2 and 3, it is worthwhile to examine the actual stability behavior of the two units. There are only 4 data points to consider. With all the caveats attending an extremely small sample size, it is a necessary exercise. Both steam generators in Unit 3 exhibited an advanced state of unstable behavior after 11 months of operation. In contrast, only one steam generator in Unit 2 exhibited "incipient instability" after 22 months of operation. Two out of two observations of instability in Unit 3 at II months leads to a 50% confidence estimate of probability of instability of 0.71 (0.71 *0.71 = 0.5). This would be a minimum expected value since TTW estimates place the onset of instability near the beginning of the operating interval. Thus a probability somewhere near 0.7 early in life is expected. For Unit 2, with one out of two observations of instability at 22 months the 50% confidence estimate of probability of instability is 0.29. This would place the occurrence of no instability in either steam generator as a 50/50 proposition ((1-0.29)*(1-0.29) =

0.5) and the chance of instability occurring in both steam generators at 22 months at a probability of 0.08 (0.29*0.29 = 0.08).

The other point regarding the observed stability behavior is the location in the tube bundle where instability first developed. This is taken to be near the maximum observed TTW depths. These observations regarding actual stability behavior provides a means of evaluating the reasonableness of probability of instability calculations.

Calculated probabilities should be in reasonable agreement with observed behavior.

Figure 8-3 provides a summary of probability of instability calculations. Figure 8-3 requires careful reading of the notes and legends. It traces the probability of instability versus time for Units 2 and 3. All results are based on 95t' percentile stability ratios. First consider results for the probability of instability versus time for 100% power and instability defined as a stability ratio of 1 or more. This serves as a check of results to be reported for a stability ratio of 0.75 which is the main item of interest, that is, demonstrating margin. [

Unit 2 has more substantial contact forces and is much more resistant to loss of support effectiveness due to wear at AVB locations. After 22 months, the calculated probability of instability is about 0.85. The intermediate point at 12 months is near 0.3. Both of these values are high and thus conservative. This is judged to be the effect of an underestimation of contact forces. [

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear Before proceeding to a drop in power from 100% to 70%, it is of interest to check the predicted most likely locations of first instability at 100% power. Projections are shown in Figure 8-4 for Unit 3 and in Figure 8-5 for Unit 2. The hotter (yellow and red) colors are the more likely locations of first instability. The U-bends plotted have the largest TTW depths. Overall, calculated locations where first instability will occur agree very well with observations. This re-enforces the reasonableness of the probability of instability calculations and supports the reliability of the probabilistic argument for margin in terms of maintaining a stability ratio less than 0.75.

As noted above, a drop to 70% power makes all U-bends stable, SR < 1, with no effective in-plane supports using the 9 5 " percentile stability ratio calculations. Since no effective in-plane supports are required, wear at AVB locations over time is not an issue. Stability will be maintained indefinitely.

The desired margin for stability is a projected maximum stability ratio of 0.75 with 0.95 probability at 50%

confidence over the next inspection interval of 5 months. The green line in Figure 8-3 shows that a maximum stability ratio of 0.75 will be maintained with 0.95 probability at 50% confidence for 8 months after restart at 70%

power. Note that this is the same as stating the probability of instability for SR = 0.75 or greater is less than or equal to 0.05. That is, the green line on Figure 8-3 is below the red line, 0.05 probability, for 8 months. This is a conservative demonstration of margin. The probability of instability at 100% power for SR > I is conservatively high. This means support effectiveness is better than calculated at both 100% power and even then more so at 70% power. Recall the demonstrated stability at 100% power at EOC 16 necessitated that there were no more than 4 consecutive ineffective supports in the worst case region. Hence stability immediately upon restart as 70%

power even for stability in terms of SR < 0.75 is required. The calculated probability of instability at SR > 0.75 immediately upon restart is 0.012; it is not zero because for an SR threshold of 0.75 there is a population of tubes that require between I and 3 effective AVBs to be stable, and the random gap distributions input to the Monte Carlo trials produce this condition for the susceptible population of tubes a small percentage of the time. [

I With no effective in-plane supports the stability ratio of the two tubes with TTW, RI II C81 and R 113 C81 in SG 2-89, is 0.88 at 70% power (Attachment 5 of [20]). It is an open question as to how many supports were effective at 100% power. It is highly likely that there are not 9 consecutive ineffective supports on these tubes under the moderate conditions of 70% power. Substantial margins are demonstrated at 70% power as the probability of maintaining a maximum stability ratio of 0.75 is greater than 0.95 for 8 months with conservative calculations.

Other items of conservatism in the analysis are projected wear depth growth rates at AVB locations based on a constant rate of volume loss at levels observed at 100% power and the use of a support effectiveness criteria at 70% power that is effectively the same as at 100% power. In this later context, it is noted that use of the single parameter criteria for support ineffectiveness at [ ] provides essentially the same probability of instability as use of the log normal distribution of probability of support ineffectiveness with a [ ] median value and an upper tail based on the upper bound contact force for support ineffectiveness.

One final item is needed for completeness, although the answer is obvious based on the results for a stability ratio threshold of 0.75. Long term stability at 70% power was argued in Section 5.0 even for a 99t" percentile stability ratio calculation. With the 9 9 th percentile stability ratios and stability based on SR > 1, the probability of instability for 12 months after restart is 0.0001. Long term stability will be maintained and large margins are conservatively demonstrated.

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AR EVA SONGS U2C17 Steam Generator Operational Assessment for Tube-to-Tube Wear 9.0 DEFENSE-IN-DEPTH Defense in depth measures relative to TTW in Unit 2 add to the assurance that structural and leakage integrity requirements will be maintained throughout the next inspection interval. These measures go beyond the technical case for restart of Unit 2 at 70% power. A decrease in power to the 70% level returns the steam generators back inside the operational envelop of demonstrated successful performance and assures stability without dependence on any effective in-plane supports. Thus structural and leakage integrity of steam generator tubing is demonstrated. Also, substantial margins have been shown. Still, conservatism demands that the question of the consequences of developing in-plane fluid-elastic instability be addressed. Defense in depth measures are in place to mitigate these consequences if needed in extremis.

Tubes with a high risk of developing FEI, based on AVB wear patterns similar to those of unstable tubes in Unit 3, have been plugged. Wire cable stabilizers have been inserted. Figure 9-1 and Figure 9-2 show tubesheet maps, for Unit 2 SG E-088 and SG E-089 respectively, of tubes preventively plugged for increased susceptibility to in-plane FEI. If FEl occurs, the location will most likely be in the high risk region. Then FEI must progress through a buffer zone of plugged tubes to reach pressurized, in service tubes. From probability calculations this process of instability zone expansion took about 7 months to develop in Unit 3. Only at this point is an in-service pressurized tube driven to instability with consequent development of TTW. Only when instability develops for an in-service tube does structural and leakage integrity begin to be challenged. The preventive plugging patterns shown in Figure 9-1 and Figure 9-2 are based solely on AVB wear patterns in each given tube not a buffer zone concept based on possible instability zone expansion. Therefore there are gaps in the buffer zone. Consequently the time for possible instability zone expansion in Unit 2 at 70% power is reduced to half of the 7 month estimate from Unit 3. It is estimated at 3.5 months.

The function of the wire cable stabilizers is to prevent tube severance in plugged tubes should instability and instability zone expansions develop. Stabilizers provide additional damping for large amplitudes of motion of U-bends and this will mitigate TTW growth rates to some degree. After instability, deep wear scars can develop over time at the 480 U-bend positions on the hot leg and cold leg as well as at the top tube support plate. [

] Stabilizers will prevent the generation of large loose parts if instability and instability zone expansion occurs.

With the assumption of instability and the subsequent instability zone expansion, eventually an in-service pressurized tube will be driven to instability. TTW will occur over time to an extent challenging structural and leakage integrity. For SONGS Unit 2, the SIPC is that the worst case projected wear will not lead to a tube burst at 3 times the normal operating differential pressure, 3AP. [

J The actual physical wear depth associated with meeting the SIPC is approximately [ .

For information purposes, the wear depth leading to failure at SLB conditions is [ ] and a tube burst at NOPD requires degradation that is [ . These values are based on very long, uniformly deep wear scars such as is expected from TTW.

Now the question of interest is "After TTW begins how long does it take to reach an unacceptable level of wear depth?". After 11 months of operation of Unit 3 the TTW depths of 3 tubes, based on ECT results, exceeded 75%

TW. Estimates of wear depth growth rate for the tube with the worst case depth, R106 C78 in Unit 3, SG 3-88 were developed using three different approaches:

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" Simple estimates

• Dynamic (time domain) modeling of U-bend impact with spring loaded contact areas under turbulence and fluid-elastic excitation.

" Dynamic (time domain) finite element analysis of one U-bend impacting a neighboring U-bend employing a parametric study of forcing function amplitude, conventional damping, and Coulomb (friction) damping during U-bend to U-bend contact.

Results are summarized below. More details are provided in Appendix A for the simple estimates and FEA dynamic analysis of one U-bend impacting its neighboring U-bend. Dynamic modeling of a U-bend impacting spring loaded contact areas is described in Appendix 10 of Reference [20]. All of these analyses assume that the TTW coefficient is the same as determined in wear tests of Alloy 690 wear couples in a secondary side environment under tests conditions (including SONGS SGs) appropriate for turbulence induced wear at AVB locations. It is an open question as to whether or not these wear coefficients are directly applicable to the higher loads and much larger single event sliding distances that are present with tube-to-tube impacts.

Dynamic modeling of a U-bend impacting spring loaded contact areas indicated that work rates and thus volumetric loss rates are consistent with the development of the worst case wear depth in approximately I I months. This would be consistent with instability beginning in Unit 3 shortly after start-up. Simple estimates of wear rates with consideration of uncertainties in impact forces and wear coefficients set the range of worst case TTW occurring between 2.5 and 11 months. Sophisticated parametric dynamic FEA analysis of one U-bend impacting another show that contact forces and contact lengths vary from one impact event to another and vary even during an impact event. Contact forces were shown to be highly dependent on how tightly a neighbor tube is held in place by its own AVBs as it is impacted by an unstable tube. Further, evaluation of elongated wear scars at AVB locations reveals that the worst case tube, Unit 3 SG E-088 R106 C78, had a substantial amplitude of motion during instability to the point where two outboard neighbors (higher row same column) and two inboard neighbors had to be involved in impact events due to the motion of tube R106 C78. This multiple tube event was not included in any wear estimate. Given these uncertainties the estimated range of wear time for the worst case flaw remains between 2.5 and 11 months after an in-service pressurized tube becomes unstable.

The defense in depth argument then is a combination of time for instability zone expansion (3.5 months) and wear time of an in-service pressurized tube (2.5 months) driven to instability at the boundary of the expansion zone.

Under the assumption that instability at 70% power begins immediately upon restart, a highly improbable circumstance, the minimum estimate for time to violate structural and leakage integrity requirements in an unplugged tube is 6 months. This is longer than the planned operating time of 5 months. This is not unreasonable given the extremely conservative assumption of instability occurring immediately upon restart at 70% power.

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SCE ATTACHMENT 13 NRC Enforcement Policy June 7, 2012 U. S. Nuclear Regulatory Commission Office of Enforcement Washington, DC 20555-00

NRC Enforcement Policy NRC ENFORCEMENT POLICY CONTENTS PREFACE ............................................................................................................................. 3

1.0 INTRODUCTION

.................................................................................................... 4 1.1 Purpose .............................................................................................................. 5 1.2 Applicability......................................................................................................... 5 1.3 Statutory Authority .............................................................................................. 6 1.4 Regulatory Framework........................................................................................ 6 1.5 Adequate Protection Standard ............................................................................ 6 1.6 Responsibilities....7 2.0 NRC ENFORCEMENT PROCESS ....................................................................... 7 2.1 Identification of Violations .............................................................................. 8 2.2 Assessment of Violations ............................................................................... 8 2.2.1 Factors Affecting Assessment of Violations ........................................ 8 2.2.2 Severity Levels ................................................................................. 10 2.2.3 Operating Reactor Assessment Program ......................................... 11 2.2.4 Exceptions to Using Only the Operating Reactor Assessment Program ....................................................................... 11 2.2.5 Export and Import of NRC-Regulated Radioactive Material and Equipment ................................................................................. 12 2.2.6 Construction ..................................................................................... 12 2.3 Disposition of Violations ............................................................................... 13 2.3.1 Minor Violation.................................................................................. 13 2.3.2 Non-Cited Violation .......................................................................... 13 2.3.3 Notice of Violation ............................................................................ 15 2.3.4 Civil Penalty ..................................................................................... 15 2.3.5 Orders .............................................................................................. 22 2.3.6 Demand for Information.................................................................... 23 2.3.7 Administrative Actions ...................................................................... 23 2.3.8 Reopening Closed Enforcement Actions .......................................... 23 2.3.9 Enforcement Guidance Memoranda ................................................. 23 2.3.10 Commission Notification and Consultation on Enforcement Actions . 24 2.4 Participation in the Enforcement Process..................................................... 24 2.4.1 Predecisional Enforcement Conference............................................ 25 2.4.2 Regulatory Conference..................................................................... 25 2.4.3 Alternative Dispute Resolution.......................................................... 26 3.0 USE OF ENFORCEMENT DISCRETION .......................................................... 26 3.1 Violations Identified during Extended Shutdowns or Work Stoppages.......... 27 3.2 Violations Involving Old Design Issues......................................................... 27 1

NRC Enforcement Policy 3.3 Violations Indentified Due to Previous Enforcement Actions ........................ 28 3.4 Violations Involving Certain Discrimination Issues........................................ 28 3.5 Violations Involving Special Circumstances ................................................. 29 3.6 Use of Discretion in Determining the Amount of a Civil Penalty ................... 29 3.7 Exercise of Discretion To Issue Orders ....................................................... 30 3.8 Notices of Enforcement Discretion for Operating Power Reactors and Gaseous Diffusion Plants ............................................................................. 30 3.9 Violations Involving Certain Construction Issues........................................... 31 4.0 ENFORCEMENT ACTIONS INVOLVING INDIVIDUALS ................................ 32 4.1 Considerations in Determining Enforcement Actions Involving Individuals ... 33 4.2 Notices of Violation and Orders to Individuals .............................................. 34 4.3 Civil Penalties to Individuals......................................................................... 35 4.4 Confirmatory Orders to Individuals ............................................................... 35 5.0 PUBLIC AVAILABILITY OF INFORMATION REGARDING ENFORCEMENT ACTIONS ................................................................................ 35 6.0 VIOLATION EXAMPLES ..................................................................................... 35 6.1 Reactor Operations ...................................................................................... 36 6.2 Fuel Cycle Operations ................................................................................. 37 6.3 Materials Operations ................................................................................... 40 6.4 Licensed Reactor Operators ....................................................................... 43 6.5 Facility Construction (10 CFR Part 50 and 52 Licensees and Fuel Cycle Facilities) ..................................................................................................... 46 6.6 Emergency Preparedness ........................................................................... 47 6.7 Health Physics ............................................................................................. 48 6.8 Transportation ............................................................................................. 52 6.9 Inaccurate and Incomplete Information or Failure to Make a Required Report ......................................................................................................... 53 6.10 Discrimination .............................................................................................. 57 6.11 Reactor, Independent Spent Fuel Storage Installation, Fuel Facility, and Special Nuclear Material Security ..................................... 59 6.12 Materials Security ........................................................................................ 61 6.13 Information Security .................................................................................... 65 6.14 Fitness for Duty............................................................................................ 65 7.0 GLOSSARY .......................................................................................................... 67 8.0 TABLE OF BASE CIVIL PENALTIES ............................................................... 72 9.0 INTERIM ENFORCEMENT POLICIES .............................................................. 73 9.1 Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) .. 73 9.2 Enforcement Discretion for the Minimum Days Off Requirements of

§ 26.205(d)(3) .............................................................................................. 76 2

NRC Enforcement Policy PREFACE The U.S. Nuclear Regulatory Commission (referred to as the NRC, Commission, or Agency) Enforcement Policy sets forth the general principles governing the NRCs enforcement program and the Commissions expectations regarding the process to be used by the NRC to assess and disposition violations of NRC requirements. However, this is a policy statement and not a regulation. The Commission may deviate from this statement of policy as appropriate under the circumstances of a particular case. The Policy also describes how organizations and individuals subject to NRC enforcement actions can provide input to the process. A glossary is provided which defines specific terms or words as they are used in the context of this Policy.

The NRC Enforcement Manual contains specific processes and guidance for implementing this Policy. The guidance provided in the Enforcement Manual has been written to be consistent with this Enforcement Policy. The Enforcement Manual is available on the NRCs public Web site, http://www.nrc.gov (select Public Meetings and Involvement, then Enforcement, then Guidance, then Enforcement Manual or select Electronic Reading Room, ADAMS Documents, and search ADAMS using accession number ML102630150.)

A compilation of the statutes and materials pertaining to current nuclear regulatory legislation can be found on the NRC webpage.

Changes to the NRC Enforcement Policy since it was first published with links to a summary of each change and the Federal Register notice for each change are maintained on the NRC Office of Enforcement webpage.

3

NRC Enforcement Policy or if the violation or conduct causing the violation is willful. In such cases, the Order may provide, for stated reasons, that the proposed action be immediately effective pending further action. Otherwise, the Agency grants a prior opportunity for a hearing on the Order.

The NRC may also issue Orders to nonlicensees, including contractors and subcontractors, holders of NRC approvals (e.g., certificates of compliance, early site permits, standard design certifications, or applicants for any such approvals), and to employees of any of the foregoing and to licensed individuals, such as licensed reactor operators, and nonlicensed individuals.

2.3.6 Demand for Information The Commission may also issue a demand for information (DFI) (see 10 CFR 2.204) to determine whether an Order under 10 CFR 2.202 should be issued or whether other action should be taken.

2.3.7 Administrative Actions The NRC also uses administrative actions, such as confirmatory action letters, notices of deviation, and notices of nonconformance, to supplement its enforcement program. These administrative actions are explained in the Enforcement Manual and defined in the glossary of this Policy. The NRC expects licensees and other persons subject to the Commissions jurisdiction to adhere to any obligations and commitments resulting from administrative actions and will consider issuing additional Orders, as needed, to ensure compliance.

2.3.8 Reopening Closed Enforcement Actions Under special circumstances (e.g., when the NRC receives significant new information indicating that an enforcement sanction was incorrectly applied), the Agency may consider, on a case-by-case basis, reopening a closed enforcement action to increase or decrease the severity of a sanction or to correct the record.

Special circumstances include but are not limited to (1) a situation where persons provided incomplete or inaccurate information that would have been considered material to the NRCs disposition of a case, (2) information was deliberately withheld or obscured, or (3) the licensee made errors in calculations that would not have normally been reviewed by the NRC. Special circumstances do not normally include the discovery of additional information that was reasonably available to the NRC at the time the Agency made its initial enforcement decision unless the Commission determines that action is necessary to ensure that the facility provides adequate protection to the health and safety of the public and is in accord with the common defense and security.

2.3.9 Enforcement Guidance Memoranda Enforcement guidance memoranda (EGM) are used to provide the NRC staff with temporary enforcement guidance, including, in some instances, enforcement discretion, when the criteria specified in the EGM are met. EGM normally describe the situation that has occurred that requires the use of such guidance, as well as the length of time the EGM will be in effect. For a list of current EGM, see Appendix A of the NRC Enforcement Manual.

23

NRC Enforcement Policy

3. A licensee violates the requirements of 10 CFR Part 26, but the violation is unrelated to the behavior observation program and does not amount to a Severity Level I, II, or III violation; or

4. Failures to appropriately implement any of the requirements (e.g., work hours, waivers, self declarations, or fatigue assessment) of 10 CFR Part 26, Subpart I that are not isolated or that demonstrate programmatic weaknesses in implementation.

7.0 GLOSSARY This glossary, while not exhaustive, contains many of the terms commonly used throughout the NRC enforcement process.

Activity Area refers to the area of NRC-licensed activity that a licensee (or other person) engages in (e.g., radiography, reactor operations).

Actual Consequences include such effects as actual onsite or offsite releases of radiation, onsite or offsite radiation exposures, accidental criticality, core damage, loss of significant safety barriers, and loss of control of radioactive material.

Adverse Action is any action that may adversely impact the compensation, terms, conditions, or privileges of employment including but not limited to a failure to receive a routine annual pay increase or bonus; demotion or arbitrary downgrade of a position; transfer to a position that is recognized to have a lesser status or be less desirable (e.g., from a supervisory to nonsupervisory position); failure to promote; overall performance appraisal downgrade; verbal or written counseling, or other forms of constructive discipline.

Alternative Dispute Resolution (ADR) refers to a variety of processes that emphasize creative, cooperative approaches to handling conflicts in lieu of adversarial procedures.

Mediation and arbitration are the most widely recognized processes. The NRCs ADR program uses mediation rather than arbitration (i.e., the parties develop mutually agreeable corrective actions rather than being obligated by an arbitrators decision).

Apparent Violation is a violation of regulatory requirements that is being considered for escalated enforcement action.

Careless Disregard refers to situations in which an individual acts with reckless indifference to at least one of three things: (1) the existence of a requirement, (2) the meaning of a requirement, or (3) the applicability of a requirement. Careless disregard occurs when an individual is unsure of the existence of a requirement, the meaning of a requirement, or the applicability of the requirement to the situation, but nevertheless proceeds to engage in conduct that the individual knows may cause a violation. Although aware that the action might cause a violation, the individual proceeds without first ascertaining whether a violation would occur.

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NRC Enforcement Policy Civil Penalty is a monetary penalty that may be imposed for violations of (1) certain specified provisions of the AEA or supplementary NRC rules or Orders, (2) any requirements for which a license may be revoked, or (3) reporting requirements under Section 206 of the ERA.

Confirmatory Action Letter (CAL) is a letter confirming a licensees or contractors agreement to take certain actions to remove significant concerns regarding health and safety, safeguards, or the environment.

Confirmatory Order is an Order that confirms the commitments made by a license or individual to take certain actions. Before issuance of the Confirmatory Order, the licensee or individual and the NRC mutually agree on the terms of the Order.

Contractor, as used in this Policy, includes vendors who supply products or services to be used in an NRC-licensed facility or activity.

Corrective Action Program is a licensees process for tracking, evaluating, and resolving deficiencies.

Deliberate Misconduct occurs when an individual voluntarily and intentionally (1) engages in conduct that the individual knows to be contrary to a requirement, procedure, instruction, contract, purchase order, or policy of a licensee, applicant for a license, or a contractor or subcontractor of a licensee or applicant for a license or (2) provides materially inaccurate or incomplete information to a licensee, applicant for a license, or a contractor or subcontractor of a licensee or applicant for a license.

Demand for Information (DFI), as defined in 10 CFR 2.204, requires a licensee or other person subject to the jurisdiction of the Commission to respond with specific information for the purpose of enabling the NRC to determine whether an Order should be issued or whether other action should be taken.

Discrimination, as described in 10 CFR 10 CFR 50.7 (or similar provisions in 10 CFR Parts 30, 40, 52, 60, 61, 63, 70, 71, 72, and 76), is the taking of an adverse action against an employee because the employee engaged in certain protected activities.

Escalated Enforcement Actions include Severity Level I, II, and III NOVs; NOVs associated with an inspection finding that the SDP evaluates as having low to moderate (white) or greater safety significance; civil penalties; NOVs to individuals; Orders to modify, suspend, or revoke NRC licenses or the authority to engage in NRC-licensed activities; and Orders issued to impose civil penalties.

Event, as used in this Policy, means (1) an occurrence characterized by an active adverse impact on equipment or personnel, readily obvious by human observation or instrumentation, or (2) a radiological impact on personnel or the environment in excess of regulatory limits, such as an overexposure, a release of radioactive material above NRC limits, or a loss of radioactive material. For example, an equipment failure discovered through a spill of liquid, a loud noise, the failure of a system to respond properly, or an annunciator alarm would be considered an event; a system discovered to be inoperable through a document review would not. Similarly, if a licensee discovers, through quarterly dosimetry readings, that employees had been 68

SCE ATTACHMENT 14 NUCLEAR REGULATORY COMMISSION ENFORCEMENT MANUAL U.S. Nuclear Regulatory Commission Office of Enforcement Revision 7 Washington, DC 20555-0001 October 1, 2010

Table of Contents ABSTRACT .................................................................................................................................................1 INTRODUCTION .................................................................................................................................... I-1 CHAPTER 1 Responsibilities and Authorities ..................................................................................... 1-1 CHAPTER 2 Dispositioning Noncompliances ..................................................................................... 2-1 CHAPTER 3 Noncited Violations and Non-Escalated Actions .......................................................... 3-1 CHAPTER 4 Escalated Enforcement Actions ...................................................................................... 4-1 CHAPTER 5 Exercise of Discretion ..................................................................................................... 5-1 CHAPTER 6 Wrongdoing ..................................................................................................................... 6-1 CHAPTER 7 Reactor Operations .......................................................................................................... 7-1 CHAPTER 8 Miscellaneous Materials Enforcement Activities........................................................... 8-1

ABSTRACT The NRC Enforcement Manual (Manual):

• is the primary source of guidance regarding agency policy and procedures for NRC staff implementing the enforcement program

• contains procedures, requirements, and background information that are essential to those who develop or review enforcement actions for the NRC

• provides guidance consistent with the Enforcement Policy The enforcement program was developed to implement the Enforcement Policy which supports the agencys overall safety and security mission, i.e., to protect the public health and safety and provide for the common defense and security. To emphasize the importance the Commission places on this mission, two major goals of the enforcement program are (1) to emphasize the importance of compliance with regulatory requirements, and (2) to encourage prompt identification and prompt, comprehensive correction of violations.

NOTE:

The guidance provided in this manual has been written to be consistent with the Enforcement Policy. Because it is a policy statement, the Commission may deviate from the Enforcement Policy and its implementing procedures, as appropriate, under the circumstances of a particular case. In such cases, the Administrative Procedure Act (APA) requires that agency decisions have a reasonable basis, and prohibits a decision that is arbitrary or capricious. The Enforcement Policy is revised periodically to reflect current Commission direction. Before deciding on a specific enforcement action for enforcement issues which were identified prior to the effective date of a policy revision, the staff will consider the guidance from both the previous version of the Policy and the revised version, and typically will apply the more lenient of the two policy versions.

The Manual applies to the enforcement activities of the Office of Enforcement (OE), the Regional Offices, the Offices of Nuclear Reactor Regulation (NRR), New Reactors (NRO),

Nuclear Material Safety and Safeguards (NMSS), Federal and State Materials and Environmental Management Programs (FSME), Nuclear Security and Incident Response (NSIR), International Programs (OIP), and all other special teams or task forces involved in enforcement activities. It also applies to the enforcement role of the Office of the General Counsel (OGC), with particular emphasis placed on the Associate General Counsel for Hearings, Enforcement, and Administration, and the Assistant General Counsel for Materials Litigation and Enforcement.

1

Abstract Most enforcement actions are initiated from the Regional Offices; therefore, this Manual has been structured to reflect that the Regional Offices, for the most part, initiate, recommend, or issue enforcement actions. However, all offices that conduct inspections and determine compliance should follow the guidance in this Manual.

Program offices, such as NRR, NMSS, FSME, NRO, or NSIR, that take the lead for an enforcement action, assume the responsibilities of both the Program Office and the Regional Office for that action. In such cases, the Program Office should follow the guidance applicable to both the Program Office and the Regional Office.

The Manual is a living document and is maintained on the NRC Enforcement Web site. It can also be found on the NRCs public Web site, www.nrc.gov (Select Electronic Reading Room, then Document Collections, then click on Enforcement Docs under Related Information select Enforcement Guidance). Changes to the Manual are contained in Change Notices posted in the Change Notice Index on the Enforcement Web site. Enforcement Policy changes are also documented annually in the NRC Enforcement Program Annual Report.

Questions or comments about this manual should be sent to John R. Wray, Senior Enforcement Specialist, Office of Enforcement at john.wray@nrc.gov.

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Dispositioning Noncompliances Chapter 2

6. Minor changes to requirements: Minor violations include the failure to meet 10 CFR 50.59 requirements that involve a change to the FSAR description or procedure, or involve a test or experiment not described in the FSAR, where there was no reasonable likelihood that the change would ever require NRC approval per 10 CFR 50.59, e.g.:

The licensee developed and approved a preventive maintenance task that should have required that a change be made to the plant technical specifications.

A 10 CFR 50.59 screening was not performed. When requested to perform the task, control room operators identified that the task would violate technical specifications and did not perform it.

The violation: A task was changed that would require a change to the technical specifications without first completing a 10 CFR 50.59 screening.

Minor because: The licensees established process identified the problem prior to implementation. The problem did not affect any equipment and had no safety consequences.

Not minor if: The task had been performed.

E. Violations that involve issues that are considered significant enough to be utilized in the formal NRC assessment process are not minor.

F. Inspection Manual Chapter 0612, Appendix B, Issue Screening, provides guidance for answering the more than minor questions. These questions can be used with the following guidance to determine whether identified violations are minor. Where a licensee does not take corrective action for a minor violation, willfully commits a minor violation, or the NRC has indications that the minor violation has occurred repeatedly, the matter should be considered more than minor, i.e., the matter should be categorized at least at Severity Level IV or associated with a green inspection finding and dispositioned in an NOV or NCV, as appropriate.

2.11 Tracking Enforcement and SDP Issues A. The staff tracks various enforcement and SDP issues through the use of OEs Enforcement Action Tracking System (EATS). Under this system, enforcement action (EA) numbers are assigned to a variety of issues.

1. OE or the responsible regional OE enforcement specialist will assign an EA number to each enforcement issue associated with a red, yellow, or white SDP finding. This enables OE to track violation/problem assessments.

a). If additional related escalated violations or problems or SDP issues are identified subsequent to an enforcement or SERP panel, additional EA numbers will be assigned.

b). If violations, problems, or issues are dropped subsequent to an enforcement or SERP panel, the related EA numbers should be closed.

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Dispositioning Noncompliances Chapter 2 2.11.1 Enforcement Action (EA) Numbers A. EA numbers are assigned to administratively track and file a variety of enforcement issues, including SDP issues that are addressed in enforcement or SERP.

B. EA numbers are assigned to program office orders imposing additional regulatory requirements.

C. EA numbers are generally assigned when cases are discussed during enforcement or SERP panels, whether or not the case ultimately results in enforcement action. During or subsequent to a SERP or enforcement panel, an enforcement specialist will assign an EA number to:

1. Each issue being considered for enforcement action; or

2. Each inspection finding being assessed by the SDP that does not have enforcement implications.

D. EA numbers are placed on the SDP/EA Request and Strategy Form and forwarded to the region that initiated the action for review and comments.

E. EA numbers are assigned sequentially according to the year of issuance (e.g., EA 011). Once an EA number has been assigned to a proposed violation, all subsequent documents involving the violation should include the complete five-digit EA number.

F. EA numbers are assigned to the following:

1. Any issue that is discussed during a SERP or enforcement panel, regardless of whether the issue ultimately results in an enforcement action.

2. Any case in which a predecisional enforcement conference or Regulatory Conference is scheduled.

3. Any case in which the region issues a letter giving a licensee the choice of responding to apparent violations or requesting a predecisional enforcement conference (i.e., "choice letter"), if not already issued.

4. All escalated enforcement issues. This includes those cases that require headquarters review prior to issuance, as well as those that do not. Orders that impose civil penalties retain the same EA number as the action that proposed the civil penalty.

a) Multi-sanction cases receive individual EA numbers for each sanction, e.g., a case that includes both a proposed civil penalty and a separate (stand-alone)

Demand For Information (DFI) would have one EA number for the proposed civil penalty and a separate EA number for the DFI.

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Dispositioning Noncompliances Chapter 2

5. Any case involving willfulness whether or not escalated or non-escalated enforcement action is to be issued, including willful cases where the staff proposes to exercise discretion and refrain from issuing enforcement action (e.g., NCV).

6. Severity Level IV NOVs and NOVs associated with green SDP findings involving power reactors, where an NCV is determined to be inappropriate.

7. Any issue where enforcement discretion is exercised (e.g., exercise of discretion per EGMs or the Interim Policies).

8. Non-escalated enforcement actions requiring headquarters review, including:

a) Any enforcement action requiring Commission approval; b) Any non-escalated enforcement action involving an individual; c) Any non-escalated enforcement action which, by the examples in the Violation Examples section of the Policy, could be categorized at Severity Level III or characterized as greater than green by the SDP; d) Any non-escalated enforcement action related to a current proposed escalated enforcement action, unless there has been prior approval for separate issuance by the Director, OE; e) Any case involving the mitigation of enforcement sanctions as addressed in the Enforcement Policy; f) Any case in which the staff proposes to exercise discretion and refrain from issuing an enforcement action for a transportation cask contamination violation that could be categorized at Severity Level III or above.

g) Any case in which a Notice of Enforcement Discretion (NOED) was issued and the root cause that results in the need to request the NOED was a violation in itself (regardless of whether the violation will be dispositioned as an NCV or in an NOV). The EA number should be included on the subsequent enforcement action, but should not be included on the NOED when it is issued.

h) Any case involving an OI report where enforcement action appears warranted (i.e., whether the action is based on willfulness or not and whether the action is escalated, non-escalated, or an NCV). OE will assign an EA number to the case when it determines enforcement action is warranted or when it requests an OGC analysis of whether enforcement action is supportable.

i) Any case in which the staff proposes to issue a DFI. The DFI should be given an individual EA number even if issued together with another enforcement action. If another enforcement action is issued after the response to the DFI which addresses the subject matter of the original DFI, a new EA number is also to be obtained.

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Dispositioning Noncompliances Chapter 2 j) Any case (during review and approval) in which the region proposes to issue any action to an individual (i.e., NOV, civil penalty, DFI, order, close out letter, or similar letter) k) Any case (during review and approval) in which the NRC proposes to issue an enforcement action (regardless of severity level) to a licensed operator for failure to comply with a facility licensee's fitness-for-duty (FFD) program.

l) Any case in which the NRC issues a "chilling effect" letter (CEL) for discrimination for engaging in protected activities. The region should request an EA number when it is determined that a CEL should be issued. The EA will be closed upon receipt of the licensees response to the CEL. Any subsequent enforcement action proposed will be given a new EA number.

m) Any case referred to DOJ in which the NRC is considering escalated enforcement action.

n) Any disputed minor violation, Severity Level IV violation, or violation associated with a green SDP finding (regardless of whether it was dispositioned as an NCV or in an NOV) that did not have an EA number when it was originally dispositioned. Actions (including escalated) that were originally issued with an EA number should be tracked using the existing EA number. Appropriate keywords should be used to identify the violation as disputed in EATS.

o) An order (issued by the program office) imposing additional requirements beyond the existing regulatory requirements (e.g., 2002 security orders). One EA number may be used in the event the same order is issued to multiple licensees.

The program office should contact OE (normally through their office Enforcement Coordinator) as soon as they believe an order should be issued.

p) Any issue that OE, the region, or the program office believes is warranted.

2.11.2 Preparing and Maintaining SDP/EA Request & Strategy Forms A. SDP/EA Request & Strategy Forms (Strategy Forms) are used to:

1. Summarize the agencys strategy for dispositioning SDP and enforcement issues;

2. Serve as aids during case deliberations;

3. Record the conduct of enforcement or SDP meetings and discussions about the strategy that was used; and

4. Document the basis for any change in enforcement or SDP approach.

B. To ensure that Strategy Forms fully serve their purposes, the following guidance should be implemented:

1. Every issue paneled in a SERP or enforcement panel will get an EA number whether or not the case ultimately results in enforcement action, e.g., an inspection finding 2-22

Dispositioning Noncompliances Chapter 2 characterized as white by the SDP will be assigned an EA number even if there are no violations associated with it. If a violation is associated with the white issue, only one EA number needs to be issued to address the case.

2. The OE Enforcement Specialist assigned to the case should prepare a Strategy Form following each panel. In addition to the necessary information to support EATS, the form should briefly state:

a) What was agreed to at the panel; b) If there was not agreement at the panel, a brief description of the disagreement and what actions are being taken to resolve the difference; c) Whether actions need to be taken to obtain the views of others (briefing of the managers in the normal decision chain need not be stated);

d) Whether additional investigation, interviews, or inspection activities are needed; e) Whether there is a need to revisit the agreement after further reviews of the evidence or research is conducted; f) The date the violation occurred (required for tracking the Statute of Limitations);

and g) Any other actions needed to reach an enforcement decision.

3. For cases that have not been paneled but which require an EA number, the region will submit to OE sufficient information such that the Enforcement Specialist can prepare a Strategy Form.

4. The Strategy Form should list all panel attendees.

5. Subsequent to an enforcement or SERP panel, OE will provide the Strategy Form to all panel participants.

6. The Strategy Form should, in general, be completed within five working days of the initial panel, as well as any subsequent panel, enforcement caucus, or other substantiative communication where the enforcement strategy is revisited or modified.

7. Strategy Forms are entered into ADAMS and are non-publicly available.

8. Copies of the Strategy Forms are retained by OE in the official EA case files with regional work sheets and other background documents until the file is placed in storage (usually 2 years after the case is closed), at which time the Forms may be discarded.

9. After a subsequent panel, caucus, or substantiative discussion, the Strategy Form should be updated by noting the original EA number, the date of the meeting or 2-23

Dispositioning Noncompliances Chapter 2 discussion, the form revision number (i.e., 1", 2", 3") and the outcome of the meeting, including a brief explanation of the reason for any change in strategy. The background information need not be restated unless it has changed. The updated Strategy Form is approved, distributed, and filed like the original Strategy Form.

2.11.3 Individual Action (IA) Numbers A. Use of Individual Action (IA) numbers enables the NRC to maintain a list of individuals who have been considered for individual enforcement action.

B. IA numbers are assigned to any case in which correspondence is addressed to an individual concerning potential enforcement action; however, the region should use an EA number for the review and approval stages and get an IA number from OE when the correspondence is ready to be issued.

C. When an IA number is assigned, all external correspondence is included in a separate system of records (NRC-3, "Enforcement Actions Against Individuals"). By the notice establishing this system of records, individual actions and correspondence with individuals may be maintained by personal identifier in NRC offices.

NOTE:

IA numbers are assigned by OE to administratively track and file all correspondence issued to an individual, if that individual is being considered for or has been issued an enforcement action. The EA number associated with the action should not appear on the correspondence issued with an IA number and should not appear in the ADAMS profile.

D. IA numbers should be used:

1. On all close-out letters and conference or choice letters to an individual; and

2. Throughout an individuals case, including any subsequent actions, e.g., Noncited Violation (NCV), NOV, civil penalty, DFI, order, or close-out letter. This includes NOVs issued to licensed operators for FFD violations, (regardless of severity level).

E. Like the original correspondence, the region should use the EA number for the draft action through the review and approval stages and include the IA number on the final action when it is ready to be issued. The EA file should be closed upon issuing the final IA action.

F. IA numbers are not assigned to cases in which a DFI or order involving an individual is issued to the licensee, unless the correspondence is directed to an individual concerning his or her performance, in which case, paragraph "a." applies.

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Non-Cited Violations and Non-Escalated Actions Chapter 3

4. As a general rule, multiple examples of the same nonconformance during the period covered by an inspection should be included in one citation.

a). The "contrary to" paragraph should generally be followed by "...as evidenced by the following examples:" and examples delineated as 1, 2, 3, etc.

b). When the examples of a particular nonconformance are numerous, sufficient examples should be cited to convey the scope of the nonconformance and to provide a basis for assessing the effectiveness of the corrective actions.

Normally three to five examples is adequate.

5. A request for the vendor or certificate holder to provide a response which includes a description of the actions taken or planned to correct the nonconformances, the actions taken or planned to prevent recurrence, and the date when the corrective actions were or will be completed.

D. Cover letters that transmit inspection reports and NONs should be prepared using the appropriate form in Appendix B.

3.4.2 Notification, Mailing, and Distribution of NONs Vendors or certificate holders are normally sent NONs at the time an inspection report is issued.

NONs are made available to the Public in accordance with agency procedures.

3.5 Confirmatory Action Letter (CAL)

A. Confirmatory Action Letters (CALs) are letters issued to licensees or vendors to emphasize and confirm a licensee's or vendor's agreement to take certain actions in response to specific issues. The NRC expects licensees and vendors to adhere to any obligations and commitments addressed in a CAL.

B. CALs should only be issued when there is a sound technical and/or regulatory basis for the desired actions discussed in the CAL.

1. CALs must meet the threshold defined in the Enforcement Policy, i.e., "to remove significant concerns about health and safety, safeguards, or the environment."

NOTE:

The level of significance of the issues addressed in a CAL should be such that if a licensee did not agree to meet the commitments in the CAL, the staff would likely proceed to issue an order.

2. CALs should be limited to those cases where the issues involved clearly meet the threshold described in the preceding paragraph.

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Non-Cited Violations and Non-Escalated Actions Chapter 3 C. Even though a CAL by definition confirms an agreement by the licensee to take some described action, it may, at times, require some negotiation with the licensee prior to issuance.

1. The licensee must agree to take the action.

2. Once a CAL is agreed upon, the licensee is expected to take the documented actions and meet the conditions of the CAL.

D. A CAL may be issued when a materials licensee is violating a particular license condition, but the license condition prescribes neither the action nor the timeliness for restoring compliance as would be prescribed by a reactor licensee's technical specification action statement.

1. A CAL would be useful in this type of situation to confirm compensatory actions which, if implemented, would ensure safety such that an immediate suspension of licensed activities might not be necessary.

2. The use of a CAL in this situation is generally reserved for materials licensees.

3. A NOED would be the appropriate tool for reactor licensees and gaseous diffusion plants if the issue is addressed by a license or certificate condition.

NOTE:

CALs are flexible and valuable tools available to the staff to resolve licensee issues in a timely and efficient manner, e.g., when an order is warranted to address a specific issue, a CAL is a suitable instrument to confirm initial, agreed upon, short-term actions covering the interval period prior to the actual issuance of the order.

E. CALs may be issued to confirm the following types of actions (note that this is not an exhaustive list):

• In-house or independent comprehensive program audit of licensed activities

• Correction of training deficiencies, e.g., radiological safety, etc.

• Procedural improvements

• Equipment maintenance

• Equipment operation and safety verification

• Voluntary, temporary suspension of licensed activities

• Licensees agreement to NRC approval prior to resumption of licensed activities

• Root cause failure analyses

• Improved control and security of licensed material F. On occasion, licensees elect to submit letters to the NRC addressing actions that they intend to take in reaction to safety issues.

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Non-Cited Violations and Non-Escalated Actions Chapter 3

1. Depending on the significance of the issues involved, the staff may elect to issue a brief CAL accepting the licensees letter and commitments; however, this practice should not be routine.

2. CALs should be limited to those cases where the issues involved clearly meet the threshold for issuing a CAL discussed above.

G. CALs may be used to confirm that a licensee will adhere to existing provisions.

1. CALs should not be used to remove an individual from, or restrict his or her ability to perform, licensed activities. Such action normally requires an order, not only to ensure enforceability, but because individual rights are affected and the opportunity for a hearing must be given both to the licensee and the affected individual.

NOTE:

The issuance of an order, in lieu of a CAL, should be considered whenever there is a need to ensure that a legally binding requirement is in place. Orders must be coordinated between the regional office, the appropriate program office, OGC, and OE.

2. Orders should be issued instead of CALs in the following situations:

a). When it is apparent that the licensee will not agree to take certain actions that the staff believes are necessary to protect public health and safety and the common defense and security; b). When there is an integrity issue; c). When there is some likelihood that a licensee may not comply with a CAL commitment; or d). When the staff has concluded that the CAL will not achieve the desired outcome.

3.5.1 Noncompliance with CALs A. CALS do not establish legally binding commitments with the exception of the reporting provisions contained in Section 182 of the Atomic Energy Act, as amended (AEA) and its implementing regulations which require a licensee to notify the NRC when:

1. The licensees understanding of its commitments differs from what is stated in a CAL;

2. The licensee cannot meet the corrective actions schedule; and

3. The licensees corrective actions are completed.

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Non-Cited Violations and Non-Escalated Actions Chapter 3 B. Failure to provide the reports required by Section 182 of the AEA may be treated like any other violation of a legally binding requirement.

C. Failure to meet a commitment in a CAL can be addressed through;

1. An NOD;

2. An order where the commitments in a CAL would be made NRC requirements; and

3. A Demand For Information (DFI) where the licensee's performance, as demonstrated by the failure to meet CAL commitments, does not provide reasonable assurance that the NRC can rely on the licensee to meet the NRC's requirements and protect public health and safety or the common defense and security.

D. Issuance of a CAL does not preclude the NRC from taking enforcement action for violations of regulatory requirements that may have prompted the issuance of the CAL.

Such enforcement action is intended to:

1. Emphasize safe operation in compliance with regulatory requirements; and

2. Clarify that the CAL process is not a routine substitute for compliance.

E. The NRC would not normally take additional enforcement action for those violations that continue after a CAL has been issued where compensatory actions have been accepted by the NRC and taken by the licensee in accordance with its commitments.

3.5.2 Preparing a CAL A. CALs should be prepared using the appropriate form in Appendix B and should include the following elements:

1. A brief discussion of the specific issues with which the NRC has concern, including how and when they were identified.

2. A brief statement summarizing NRC/licensee communication on the agreed-upon actions.

a). The statement should include when the communication took place, the names and positions of the principal individuals involved in the communication, and whether the communication took place in a telephone conversation or a face-to-face meeting.

b). Face-to-face meetings should also include the location of the meeting (i.e.,

regional office, licensee's facility).

3. A clear description of the agreed-upon actions and where warranted and appropriate, the date(s) when actions will be completed.

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Non-Cited Violations and Non-Escalated Actions Chapter 3

4. A statement that requires the licensee to provide written notification to the NRC if its understanding of the relevant issues and commitments differ from what is stated in the CAL.

5. A statement that requires the licensee to provide written notification to the NRC if for any reason it cannot complete the actions within the specified schedule. It should also require that the licensee inform the NRC of the modified schedule.

6. A statement that requires the licensee to provide written notification to the NRC if it intends to change, deviate from, or not complete any of the documented commitments, prior to the change or deviation.

7. A statement that requires the licensee to provide the NRC with written confirmation of completed actions.

8. A statement that issuance of the CAL does not preclude issuance of an order formalizing the commitments in the CAL or requiring other actions nor does it preclude the NRC from taking enforcement action for violations of NRC requirements that may have prompted the issuance of the CAL.

9. A statement that failure to meet the commitments in a CAL may result in an order if the licensees performance, as demonstrated by the failure to meet CAL commitments, does not provide reasonable assurance that the NRC can rely on the licensee to meet the NRCs requirements and protect public health and safety or the common defense and security.

10. A statement that the letter and any licensee response will be made available to the Public.

11. Citation of the regulation implementing Section 182 of the AEA and authorizing the required responses to the CAL by the licensee.

3.5.3 CAL Coordination and Review A. CALs should be coordinated and reviewed according to the following guidelines:

1. CALs issued by the region must be coordinated with the appropriate program office by telephone prior to issuance.

a). Unless NMSS requests, CALs issued to materials licensees do not require NMSS concurrence.

b). CALs issued to reactor licensees must be concurred on by the Director, NRR.

c). Because NSIR is responsible for coordinating security assessment activities across the spectrum of NRC licensees, CALs issued to NRC licensees which include security-related provisions, must be concurred on by the Director, NSIR.

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Non-Cited Violations and Non-Escalated Actions Chapter 3

2. Regional Enforcement Coordinators should be consulted before the region issues a CAL.

3. Applicable Program Office Enforcement Coordinators should be consulted before the program office issues a CAL.

NOTE:

CALs should not be used to remove an individual from, or restrict his or her ability to perform, licensed activities. Such action normally requires an order, not only to ensure enforceability, but because individual rights are affected and the opportunity for a hearing must be given both to the licensee and the affected individual.

4. CALs issued by NRR, NMSS, FSME, NRO or NSIR, must be coordinated with the appropriate region. This coordination will help to provide consistency between the regions and program offices in response to similar issues and provide program oversight and assistance.

5. Unless OE requests, CALs do not need to be coordinated with or concurred in by OE.

3.5.4 CAL Signature Authority CALs should be signed and issued according to the following guidelines:

A. The Regional Administrator should sign all CALs issued by the region. Delegation of signature authority should not be below the Division Director or acting Division Director level.

B. The Director, NRR, the Director, NMSS, the Director, FSME, the Director, NRO, or the Director, NSIR, should sign all CALs issued by NRR, NMSS, FSME, NRO or NSIR, respectively. Delegation of signature authority should not be below the Division Director or acting Division Director level.

3.5.5 Licensee Notification, Mailing, and Distribution for CALs A. CAL distribution:

1. CALs should be sent to the licensee by either Certified Mail (Return Receipt Requested) or Express Mail.

2. Upon issuance, CALs should be distributed to:

• OE

• The appropriate Deputy EDO 3-34

Non-Cited Violations and Non-Escalated Actions Chapter 3

• The appropriate program office (i.e., NRR, NMSS, FSME or NSIR)

• The appropriate region

• The appropriate Regional Public Affairs Officer

• The Regional State Liaison Officer

• The State

• For material licensees, a copy should be sent to the Regional State Agreements Officer

3. CALs should, where possible, be made available to the Public.

B. The staff should be sensitive to describing agreed upon licensee corrective actions that involve safeguards matters to prevent inadvertent release of safeguards information.

3.5.6 CAL Tracking Responsibilities A. The issuing office (i.e., region, NRR, NMSS, FSME, NRO or NSIR) is responsible for tracking the CALs it has issued and should maintain a list summarizing the following information suitable for auditing actions associated with CALs, including:

1. How many CALs have been issued;

2. To whom the CAL has been issued;

3. Why the CAL was issued, i.e., a brief description of the issues; and

4. When all corrective actions were or will be completed.

B. CAL tracking numbers will be assigned as follows:

1. The region will assign CAL tracking numbers based on the region number, the year of issuance, and the sequential CAL number in that region for that year (e.g., 2 008).

2. NRR, NMSS, FSME, NRO and NSIR will assign CAL tracking numbers in the same manner as the regions, e.g., NRR-06-006, NMSS-06-003, NSIR-06-002.

3. In cases where NSIR has the lead for the enforcement action, NSIR may, with agreement from NMSS, FSME, NRO or NRR as applicable, use the tracking system of the Office responsible for the license.

C. Addendums to CALs should retain the same CAL number followed by an alphabetical reference based on the corresponding addendum for that CAL (e.g., 2-00-008A, NRR 006B).

3.5.7 Closing Out CALs A. A CAL may or may not require follow-up inspection to verify completion of the specified licensee actions. Whether the staff believes that an inspection is necessary to close a 3-35

Non-Cited Violations and Non-Escalated Actions Chapter 3 CAL will be determined on a case-by-case basis and will depend on the circumstances of the case.

B. The issuing office (i.e., region, NRR, NMSS, FSME, NRO or NSIR) will issue documentation formally closing out the CAL.

C. Correspondence closing out a CAL should be sent to the same person/address as the CAL; however, verbal notification, in advance of written correspondence, may be sufficient to permit plant restart or resumption of affected licensee activities.

3.5.8 Press Releases for CALs Press releases are not routinely issued to address the issuance of a CAL. If a region believes that a press release is appropriate, it should be coordinated with Public Affairs which will make that determination.

3-36

Escalated Enforcement Actions Chapter 4 c). Escalated enforcement packages are to be mailed by either Certified Mail (Return Receipt Requested) or Express Mail. If facsimile equipment is not available, escalated enforcement packages are to be mailed by Express Mail.

3. The office in which the package is signed is responsible for its distribution.

a). Escalated NOVs should be e-mailed to AOEWEB@ when they are put in ADAMS to ensure that they are posted to the Enforcement Web site in a timely manner.

The e-mail should include a statement such as; Athe licensee has received a copy of the enforcement action.@

b). Distribution lists for NRC addressees are in Appendix D.

c). A copy should be sent to the appropriate State. (The region=s State Liaison Officer will normally handle this for program office cases, provided the Enforcement Specialist notifies the Regional Enforcement Coordinator.)

4. For all escalated enforcement actions involving medical licensees, the distribution list should include the Chairman and Board of Trustees.

B. In order to provide members of the public referenced information as soon as possible, when a press release is involved, the staff should release any escalated enforcement action to the public via ADAMS and the Enforcement Web site as soon as possible after it has notified the recipient of the enforcement action by e-mail or facsimile.

NOTE:

In all cases, the recipient(s) should receive the action before the press release is issued and before it is publically available. For individual actions, contacting the individual is sometimes problematic. In such cases, every reasonable attempt should be made to contact the individual before the press release is issued and the action becomes publicly available.

4.5.4 Licensee Response to NOV/CPs A. The provisions of 10 CFR 2.201 require that a licensee submit a written response addressing the violations included within a civil penalty action within 20 days of the date of the civil penalty action or other specified time frame; however, normally 30 days should be used.

B. If a licensee does not respond to a civil penalty action within the allotted time and the region has made several unsuccessful attempts to contact the licensee, the region should contact OE (no later than 60 days from the date of the issuance of the action) and consideration will be given to whether additional enforcement action is warranted, i.e., the 4-60

Escalated Enforcement Actions Chapter 4 case should be referred to the Attorney General, an order imposing the civil penalty should be issued, or whether some other enforcement action is warranted.

C. The region may grant extensions of up to 30 days without OE approval.

1. OE should be promptly notified of any extensions the region grants.

2. OE approval is required for extensions beyond 30 days.

3. Generally, verbal requests for extensions should be promptly followed up with written confirmation of the length of the extension and the date a reply is due. The confirmation may either be prepared by the NRC or the licensee. A copy of this follow-up correspondence is to be sent to OE and the region.

D. As discussed below, licensees may:

1. Admit the violation and pay the civil penalty;

2. Deny the violation, contest the staff's facts or conclusions, or request mitigation of the civil penalty and pay the civil penalty; or

3. Deny the violation, contest the staff's facts or conclusions, or request mitigation of the civil penalty and not pay the civil penalty.

E. If the licensee admits that the violation occurred as stated in the NOV and pays the civil penalty, the regional office is to review the licensee's corrective action. The region should notify OE, usually within two weeks of receiving the licensee's response, of the acceptability of the licensee's response.

1. Once OE has been notified by the region of the acceptability of the licensee's response, OE will send the licensee a letter acknowledging payment of the civil penalty and stating that the corrective actions described in the licensee's response will be examined during future inspections. This acknowledgment should be sent to the licensee within one week of the region's notification.

2. If the region requires additional information from the licensee:

a). The region should notify OE; and b). OE will send a letter acknowledging payment of the civil penalty and directing the licensee to provide the required information to the region.

3. In either case, after OE sends an acknowledgment letter, OE will normally close out the associated EA number, thereby formally closing the case.

F. If the licensee denies the violation, contests the staff's facts or conclusions, or requests mitigation of the civil penalty, but pays the civil penalty, the region is to review the licensee's points of contention.

4-61

Escalated Enforcement Actions Chapter 4

1. If the licensee presents additional information not previously disclosed:

a). Careful consideration should be given to the appropriateness of the original proposed action.

b). The region is to prepare an evaluation of the licensee's response and submit it to OE for possible inclusion in the acknowledgment letter sent by the Director, OE.

2. If the licensee's response does not contain new information, then the region will:

a). Prepare and submit to OE a brief response addressing only those issues that are significant and appropriate along with an assessment of the licensee's corrective action.

b). OE will coordinate with the region and issue the NRC's response letter.

3. Even if the licensee's response does not present new information, an error identified in the enforcement action must be corrected.

4. Licensee responses that contest enforcement actions but pay civil penalties should usually be acknowledged within 45 days.

5. If the licensee has paid a monetary penalty and then, based on the above review of the licensee's response, it appears that the penalty was clearly paid in error, the overpayment should be promptly returned to the licensee.

a). OE will arrange to have a check issued from the Controller's Office.

b). After it is determined that the Treasury has issued a check, OE will send a letter to the licensee explaining the modification to the civil penalty.

G. If the licensee denies the violation, contests the staff's facts or conclusions, or requests mitigation of the civil penalty, and does not pay the civil penalty, the regional office should:

1. Review the licensee's response;

2. Decide whether the civil penalty should be imposed, partially mitigated, or withdrawn; and

3. Prepare a written evaluation of the licensee's response.

a). The evaluation should:

1). Be Submitted to OE within 45 days; 2). Address the licensee's points of contention; and b). The evaluation should include:

4-62

Escalated Enforcement Actions Chapter 4 1). A restatement of each disputed violation; 2). A summary of the licensee's position concerning each disputed violation; 3). The NRC's evaluation of the licensee's position; and 4). The NRC's conclusion.

NOTE:

Processing Time: NRC processing time is defined as that time from the date the case is opened to the issuance of an enforcement action or other appropriate disposition less: (1) anytime the NRC could not act due to the case residing with DOL, DOJ, other government entity, where additional OI field work is needed, or where the licensee requests a lengthy deferment, and (2) anytime the NRC could not act due to processing FOIA requests.

4. If the region recommends that the civil penalty should be imposed, an Order Imposing Civil Monetary Penalty should be prepared with the staff's evaluation included as an appendix to the order.

5. If the region recommends that the civil penalty should be partially mitigated, an Order Imposing Civil Monetary Penalty should be prepared to reflect partial mitigation with the staff's evaluation included as an appendix to the order.

6. If the region recommends that the civil penalty should be withdrawn, the region should prepare a cover letter, for OE issuance, to the licensee with the staff's evaluation as an appendix to the letter.

4.5.5 NOV and NOV/CP Coordination and Review Output Measures A. Regional and OE (headquarters) timeliness on all escalated enforcement cases will be reported on a periodic basis to the Regional Administrators and Program Office Directors.

4-63

SCE ATTACHMENT 15 NRC INSPECTION MANUAL IPAB MANUAL CHAPTER 0351 IMPLEMENTATION OF THE REACTOR OVERSIGHT PROCESS AT REACTOR FACILITIES IN AN EXTENDED SHUTDOWN CONDITION FOR REASONS OTHER THAN SIGNIFICANT PERFORMANCE PROBLEMS

Contents 0351-01 PURPOSE ................................................................................................. 1 0351-02 OBJECTIVES ............................................................................................. 1 0351-03 APPLICABILITY ......................................................................................... 1 0351-04 RESPONSIBILITIES AND AUTHORITIES................................................. 2 04.01 Director, Office of Nuclear Reactor Regulation (NRR) ...................... 2 04.02 Director, Division of Reactor Projects, applicable Region ................. 2 04.03 Director, Division of Inspection and Regional Support (DIRS), NRR 2 04.04 Director, Division of Operating Reactor Licensing (DORL), NRR ..... 2 04.05 Director, Division of Preparedness and Response (DPR), Office of Nuclear Security and Incident Response (NSIR) .............................. 2 04.06 Director, Division of Security Operations (DSO), NSIR..................... 2 0351-05 BACKGROUND ......................................................................................... 2 0351-06 OUTAGE AND INSPECTION ACTIVITIES ................................................ 3 06.01 Inspection Plan ................................................................................. 3 06.02 Performance Indicator Program ........................................................ 5 06.03 Communication Plan......................................................................... 5 06.04 ROP Web Page ................................................................................ 6 0351-07 RECORDS ................................................................................................. 6 0351-08 REFERENCES........................................................................................... 7 Issue Date: 04/05/11 i 0351

0351-01 PURPOSE 01.01 To establish guidance for Reactor Oversight Process (ROP) implementation at plants in an extended shutdown condition for reasons other than significant performance problems.

01.02 To ensure that when the plant is in an extended shutdown condition, the Nuclear Regulatory Commission (NRC) communicates unified and consistent oversight in a clear and predictable manner to the licensee, public, and other stakeholders.

01.03 To ensure other Federal agencies, such as the Federal Emergency Management Agency (FEMA), the Environmental Protection Agency (EPA), the Department of Justice (DOJ), and the Department of Homeland Security (DHS), and State and local government representatives are involved and informed as necessary.

0351-02 OBJECTIVES 02.01 To provide guidance for developing an inspection plan outlining the specific inspections related to the return of the plant to power operation and necessary adjustments to the baseline inspection.

02.02 To provide further guidance concerning the applicability of the Performance Indicators (PIs) that may be invalid in an extended shutdown condition.

02.03 To provide a mechanism for communicating status of NRC oversight activities to internal and external stakeholders.

0351-03 APPLICABILITY This manual chapter may be implemented during an extended shutdown for reasons not directly related to performance problems. Consistent with IMC 0608, Performance Indicator Program, an extended shutdown is defined as an outage lasting 6 months or longer. IMC 0351 provides guidance for ROP implementation at plants that had been operating (before they entered into an extended shutdown) under the provisions of the ROP and IMC 0305, Operating Reactor Assessment Program. A plant in extended shutdown will still be assessed using IMC 0305 and the Action Matrix. For plants that are shutdown for lengthy periods of time (on the order of years), consideration should be given to development of a unique IMC, specific to that plant and the circumstances causing the lengthy outage. Plants that are under a Confirmatory Action Letter (CAL) that requires NRC approval to restart may be subject to IMC 0350, Oversight of Reactor Facilities in a Shutdown Condition Due to Significant Performance and/or Operational Concerns.

Issue Date: 04/05/11 1 0351

0351-04 RESPONSIBILITIES AND AUTHORITIES 04.01 Director, Office of Nuclear Reactor Regulation (NRR).

a. Develops assessment program policies and procedures.

b. Ensures uniform program implementation and effectiveness.

04.02 Director, Division of Reactor Projects, applicable Region.

a. Determines the applicability of this manual with input from NRR/DIRS, Resident Inspectors and Special Inspection Team (SIT), Augmented Inspection Team (AIT) or Incident Inspection Team (IIT) as appropriate.

b. Responsible (delegates as necessary) for the development of the Inspection and Communication Plan.

04.03 Director, Division of Inspection and Regional Support (DIRS), NRR. Concurs with the Regional decision to implement this IMC and any associated inspection plan.

04.04 Director, Division of Operating Reactor Licensing (DORL), NRR. Coordinates staff reviews of licensing actions and, where applicable, staff interaction with other Federal agencies (e.g. FEMA, EPA, DHS, DOJ,) pursuant to any applicable memoranda of understanding.

04.05 Director, Division of Preparedness and Response (DPR), Office of Nuclear Security and Incident Response (NSIR). Coordinates with FEMA and the Region regarding the offsite infrastructure and emergency preparedness capabilities to support plant restart in accordance with IMC-1601 Communication and Coordination Protocol for Determining the Status of Offsite Emergency Preparedness Following a Natural Disaster, Malevolent Act, or Extended Plant Shutdown.

04.06 Director, Division of Security Operations (DSO), NSIR. Concurs on the security inspection plan developed by the Region and coordinates with the Director, Division of Reactor Safety in the appropriate Region for the conduct of those inspections.

0351-05 BACKGROUND An operating commercial nuclear power plant may shut down for a variety of reasons, potentially involving events or conditions not directly related to performance. The maintenance required to return the plant to service during such outages could be outside the realm of what is accomplished during shorter planned outages such as Refueling Outages (RFO) and could be complicated by unanticipated technical or design issues that may have resulted in the shutdown. In the past, guidance from IMC 0350 has been used in combination with informal guidance to oversee plants in extended shutdowns. Since the extended shutdown is not related to performance issues, IMC 0350 and the negative connotations associated with the extent of increased Issue Date: 04/05/11 2 0351

oversight are not appropriate. Formalization of the IMC 0351 guidance should assist the regional offices in anticipating the impact on routine ROP activities and developing innovative approaches to implementing the ROP. While a plant in extended shutdown is still assessed using the ROP, the guidance in this chapter will help maintain consistent, reliable, and transparent oversight of power reactors in extended shutdown.

A plant will be considered for guidance of IMC 0351 when the plant is in, or the licensee anticipates, an extended shutdown. Recognizing that application of this guidance may not be necessary in all cases, Regional Management has the discretion not to implement the IMC 0351 guidance even though a plant may be in an extended shutdown.

When considering guidance of this IMC, Regional Management and NRR (if applicable) should carefully consider the following: (1) expected length of the plant shutdown, (2) the degree to which the licensee has performed an extent-of-condition evaluation pertaining to the reasons for the shutdown, and (3) the amount of discovery still required of the licensee to identify all of the technical and/or design problems associated with the shutdown.

0351-06 OUTAGE AND INSPECTION ACTIVITIES 06.01 Inspection Plan. If warranted, the Region can develop a unique inspection plan or modify the existing site inspection program to examine the root cause and corrective actions for any potential technical and/or design issues, and readiness to return the plant to full operational status. Specific areas of inspection will be dictated by the circumstances causing the extended shutdown and may change in focus or scope as shutdown activities progress. Inspection activities commensurate with the applicable column of the Action Matrix should be utilized to the maximum extent possible. When developing and modifying the inspection plan, the Region should use the baseline inspection procedures in accordance with Appendix A of IMC 2515, Light Water Inspection Program - Operations Phase, to the extent they are practical based on plant conditions, the availability of samples, and anticipated plant activities. The inspection plan can include status of ongoing and completed inspection activities related to the extended shutdown as well as future inspection activities given the current schedule and known circumstances at the time the inspection report is developed.

Although some samples may not be inspected because of plant conditions, the intent of the baseline inspection program may still be met without an increase of inspection resources by performing alternate inspections. Inspection samples and hours specifically related to operations may need to be decreased because of plant conditions, while hours and samples may be increased in the areas of problem identification and resolution and refueling/outage activities. If inspection sample size must be reduced, guidance of Section 08.04 of IMC 2515 shall be followed.

Additionally, Inspections listed in Appendix C of IMC 2515 can be performed with Regional Administrator approval in accordance with IMC 2515. Opportunities for completing the baseline inspection by performing alternate inspections shall be included Issue Date: 04/05/11 3 0351

in the inspection plan. If re-allocation of the baseline inspection is necessary for a particular shutdown, the Director, DIRS/NRR (or designee), will concur with the inspection plan.

An area that might warrant inspection is the operational readiness of the licensee for reactor restart. Because the length of the outage can present challenges to the licensees operational readiness, the number of units at the site is one variable that should be considered when assessing operational readiness. For example, a dual unit site may rotate operators between the shutdown plant and the operating plant while single unit site operators have no such opportunities to maintain their operational knowledge and skill and have a greater challenge of maintaining operational readiness.

Equipment upgrades and maintenance, procedure updates, facilities maintenance, and the status of the corrective action program should be considered as potential areas for additional inspection. Ensuring the licensee has maintained safety-related equipment current by incorporating the latest vendor bulletins and other important information into plant procedures could be another area for additional inspection during an extended shutdown because some of these systems may not be required during a shutdown.

The Region should also consider other opportunities for inspection not explicitly listed in this IMC when modifying the inspection plan.

If the circumstances require a unique inspection that is not currently documented in an inspection procedure, the inspection plan must be of sufficient detail for the inspectors to meet the clearly defined inspection objectives. The need for a new inspection procedure or temporary instruction to be created and issued in accordance with IMC 0040, Preparing, Revising, and Issuing Documents for the NRC Inspection Manual, should be considered if the shutdown is generic in nature and may apply to other operating reactors.

Effort spent on baseline and supplemental inspections should be charged to the appropriate inspection procedure in accordance with IMC 0306, Information Technology Support for the Reactor Oversight Process. Section 05.03 of IMC 0306 also provides guidance on documenting inspection procedures if the sample size must be modified. Direct inspection effort spent on special inspections as a result of an event should be charged to IP 93812 using the event response (ER) code, and the associated preparation and documentation should be charged to IP 93812 using the ERP and ERD activity codes respectively.

Inspection results should be documented in accordance with IMC 0612, Power Reactor Inspection Reports, to the extent practical. Areas where no findings are identified may be documented in greater detail than required by IMC 0612, specifically the results of those inspection activities relating to an event, the basis for the extended shutdown, or operational/restart readiness.

The Inspection Plan should be reviewed and modified as necessary on at least a quarterly basis, to ensure that the inspection schedule is optimized with anticipated plant activities. Specific licensee actions directly related to reason(s) for shutdown and Issue Date: 04/05/11 4 0351

the corresponding NRC activities can be listed in the inspection plan if deemed necessary by Regional Management.

06.02 Performance Indicator Program. Plants should continue to gather and submit PI data in accordance with IMC 0608 to the extent that the data are available under extended shutdown conditions. Some performance indicators in the initiating events, mitigating systems, and barrier integrity cornerstones may either be lapsed or may lack current data due to the extended shutdown, but indicators in the other cornerstones still provide useful indications of plant performance. The inspection plan should include consideration of any inspections necessary to compensate for performance indicators which lack current data.

Upon restart, several PIs will remain invalid until sufficient data have been collected to calculate each specific PI. In other words, the validity of each PI is dependent on the data needed to calculate the specific PI. The algorithms for calculating the different PIs, and in some cases the thresholds to determine their validity, are contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline. As an example, since the Unplanned Scrams and Unplanned Power Changes PIs in the Initiating Events cornerstone are not considered valid if there are fewer than 2,400 critical hours in the previous four quarters, it would typically take two quarters of operational data following restart for these indicators to be considered valid. Furthermore, starting up with only two quarters of critical hours makes this PI more volatile, meaning it could cross a threshold with a lower number of scrams than was intended. Mitigating System Performance Index is a valid indicator if supported by 3 years of data, so the validity of the indicator may need to be evaluated for a plant in an extended shutdown. On the other hand, the Reactor Coolant System (RCS) Activity and RCS Leakage PIs in the Barrier Integrity cornerstone are considered valid with the first quarterly data submittal following restart because the PIs can be calculated using a single months reported value at steady state power. Questions regarding the potential validity of specific indicators should be referred to the Performance Assessment Branch in NRR.

06.03 Communication Plan. The Region will consider development of a communication plan to ensure effective communication with internal and external stakeholders and openness in the status of ongoing licensee activities and associated inspection activities. In addition to a general communication plan for routine interactions with internal and external stakeholders, the Region will follow guidelines of IMC 1601 if applicable.

NRC management will determine the need for, and the level of, NRC participation with public stakeholders on a case-by-case basis. The level of appropriate public stakeholder participation varies greatly and depends on the cause of the shutdown; the interest of State and local citizens, public interest groups, the media, and elected officials; and the concerns of other Government agencies. Public stakeholder meetings have proven to be a valuable vehicle for communications with external stakeholders.

These meetings are held to describe the results of the NRCs review of the licensees activities. Public stakeholder meetings in the local area should be strongly considered so that the concerns and comments on the licensees shutdown activities can be heard.

Issue Date: 04/05/11 5 0351

FEMA should be involved in public stakeholder meetings that may involve significant discussion of the adequacy of offsite emergency preparedness to support plant restart, when appropriate. Furthermore, the Region, in coordination with NSIR, should anticipate and allow adequate time for FEMA to make a determination regarding the status of offsite emergency preparedness, as stipulated in IMC 1601.

The Region will ensure that efforts have been made to establish an open dialogue with local and State government officials and agencies. The Region should ensure that inquiries from the Office of Congressional Affairs, Congress, local and State government agencies, and various Federal agencies are promptly addressed.

Inquiries regarding the adequacy of offsite emergency preparedness should be coordinated with FEMA. Appropriate caution should be exercised to avoid the release of pre-decisional, proprietary, or Safeguards Information when responding to inquiries.

When interest extends to a foreign government (e.g., Canada), the Office of International Programs or its designee shall brief the foreign officials if the EDO deems a briefing appropriate.

06.04 ROP Web Page. PIs, inspection findings, and other applicable oversight information will be posted to the ROP Web page in accordance with IMC 0306, Information Technology Support for the Reactor Oversight Process. Because plants under the guidance of IMC 0351 do not fall outside of the ROP, the applicable Column and description in the Action Matrix will be listed in accordance with IMC 0306. The Region should also consider developing and maintaining a specific Web page to facilitate ease of public access to key information. The Web site should contain important correspondence, public meeting slides and transcripts, NRC inspection reports, and other relevant information.

0351-07 RECORDS Information on NRC and licensee actions related to the extended shutdown should be considered for inclusion in NRC inspection reports. Other forums, such as public correspondence between the licensee and the NRC or Commission papers, may be acceptable as well. The records developed for the shutdown could consist of the following, if applicable:

a. The Inspection Plan.

b. The Communication Plan.

c. Inspection reports and related correspondence.

d. Pertinent licensing actions completed by the NRC.

e. Other agency and Government actions communicated to the NRC.

Issue Date: 04/05/11 6 0351

f. Document(s) informing the licensee documenting the application of the IMC 0351 guidance.

g. ROP Feedback Form via IMC 0801, Reactor Oversight Process Feedback Program, or memorandum to DIRS providing the lessons learned to be considered for incorporation in the next revision to IMC 0351.

All documents relating to the extended shutdown may be included in the docket file and, to the extent permitted by 10 CFR 2.790, made public in accordance with NRC policy.

Pre-decisional information will not be made public until after the applicable decision has been made.

0351-08 REFERENCES IMC 0040, Preparing, Revising, and Issuing Documents for the NRC Inspection Manual.

IMC 0305, Operating Reactor Assessment Program.

IMC 0306, Information Technology Support for the Reactor Oversight Process.

IMC 0350, Oversight of Reactor Facilities in a Shutdown Condition Due to Significant Performance and/or Operational Concerns.

IMC 0608, Performance Indicator Program.

IMC 0609, Significance Determination Process.

IMC 0612, Power Reactor Inspection Reports.

IMC 0801, Reactor Oversight Process Feedback Program.

IMC 1601, Communication and Coordination Protocol for Determining the Status of Offsite Emergency Preparedness Following a Natural Disaster, Malevolent Act or Extended Plant Shutdown.

IMC 2515, Light Water Reactor Inspection Program - Operations Phase.

NRC Management Directive 8.3, NRC Incident Investigation Program.

END Attachment

1. Revision History for IMC 0351 Issue Date: 04/05/11 7 0351

ATTACHMENT 1 Revision History for IMC 0351 Commitment Issue Date Description of Change Training Training Comment Tracking Required Completion Resolution Number Date Accession Number N/A ML110030073 Researched commitments for 4 years No N/A ML11082A009 04/05/11 and found none.

CN 11-005 No explicit guidance exists that governs ROP implementation during extended outages not related to performance. In the past, guidance from IMC 0350, Oversight of Reactor Facilities in a Shutdown Condition Due to Significant Performance and/or Operational Concerns, has been used in combination with informal email guidance for plants in extended shutdowns. While plants in this condition still fall under the ROP, the reason for the extended shutdown is not related to performance issues so IMC 0350 and the negative connotations associated with the extent of increased oversight are not appropriate.

Issue Date: 04/05/11 Att1-1 0351

SCE ATTACHMENT 16 ATTACHMENT 71111.17 INSPECTABLE AREA: Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications CORNERSTONES: Initiating Events Mitigating Systems Barrier Integrity INSPECTION BASES: The inspection monitors the effectiveness of the licensee=s implementation of changes to facility structures, systems, and components (SSCs), risk significant normal and emergency operating procedures, test programs, and the updated final safety analysis report (UFSAR) in accordance with the requirements of 10 CFR 50.59. The inspection provides assurance that required license amendments have been obtained.

The inspection monitors the implementation of modifications to structures, systems, and components (SSCs). Modifications to one system may also affect the design bases and functioning of interfacing systems as well as introduce the potential for common cause failures.

This inspectable area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for which there are no indicators to measure performance.

LEVEL OF EFFORT Triennially review 6 to 12 licensee evaluations required by 10 CFR 50.59 and 12 to 25 changes, tests, or experiments that were screened out by the licensee.

Triennially review 5 to 15 permanent plant modifications 71111.17-01 INSPECTION OBJECTIVES 01.01 Verify that evaluations were performed in accordance with 10 CFR 50.59.

01.02 Verify that the design bases, licensing bases, and performance capability of SSCs have not been degraded through modifications.

01.03 Verify that procedures and design and license basis documentation affected by changes have been adequately updated.

01.04 Verify that design and license basis documentation used to support changes, and that procedures and design and license basis documentation affected by changes, reflect the design and license basis of the facility after the change has been made.

Issue Date: 10/31/08 1 71111.17

71111.17-02 INSPECTION REQUIREMENTS 02.01 Sample Selection

a. For the purpose of this inspection, permanent plant modifications include permanent plant changes, design changes, set point changes, procedure changes, equivalency evaluations, suitability analyses, calculations, and commercial grade dedications.

b. Review modifications, evaluations performed in accordance with 10 CFR 50.59, and changes, test, or experiments that the licensee determined did not require 10 CFR 50.59 evaluations based upon the following:

1. Safety Significance;

2. Risk Significance;

3. Complexity.

Substantial changes and modifications should be reviewed as samples. Samples should be of such complexity that the change affects the license basis and/or 10 CFR 50.2 Design Basis.

NOTE: Since lists of changes provided by the licensee will not necessarily indicate the complexity and scope of a change, a number of changes will need to be reviewed prior to the inspection to meet the "complexity" criteria contained in section 02.01.b. This is best accomplished by first choosing documents from the list provided by the licensee and then requesting the actual documentation for the changes. An initial review of these changes for complexity prior to the inspection will result in a smaller final list of samples.

02.02 Inspection

a. Inspection of evaluations performed in accordance with 10 CFR 50.59, and changes, test, experiments, or methodology changes that the licensee determined did not require 10 CFR 50.59 evaluations.

1. Verify that when changes, tests, or experiments were made, evaluations were performed in accordance with 10 CFR 50.59. Verify that the licensee has appropriately concluded that the change, test or experiment can be accomplished without obtaining a license amendment.

2. Verify that safety issues related to the changes, tests, or experiments have been resolved.

3. For the changes, tests, or experiments that the licensee determined that evaluations were not required, verify that the licensee=s conclusions were correct and consistent with 10 CFR 50.59.

4. Verify, as appropriate, that design and license basis documentation used to support the changes, and procedures and design and license basis documentation affected by the changes, reflect the design and license basis of the facility after the change has been made.

b. Inspection of modifications.

Issue Date: 10/31/08 2 71111.17

1. Verify that supporting design basis documentation have been updated accordingly and are still consistent with the new design. Some examples of supporting design basis documentation would be calculations, design specifications, and vendor manuals.

2. Verify that license basis documentation have been updated accordingly and are still consistent with the new design. Some examples of license basis documentation that could be affected are the UFSAR, Technical Specification and Bases, and plant specific SERs.

3. Verify that other design basis features affected by the modification have been adequately accounted for. Some examples of these type of features include structural, fire protection, flooding, EQ, and potential ECCS strainer blockage mitigation.

4. Verify that procedures and training plans affected by the modification have been updated adequately. Some examples would be abnormal operating procedures, alarm response procedures, and Licensed Operator Training Manuals.

5. Verify that affected test documentation has been updated and/or new test documentation has been initiated as required by applicable test programs.

Some examples of these type of tests would be instrument calibration, Inservice Testing, and breaker clean and inspect.

6. Verify that post-modification testing adequately verified system operability and/or functionality.

See IP 71111.18, APlant Modifications@, Section 02.02 for additional guidance regarding design review, implementation review, testing review, and updating review.

02.03 Identification and Resolution of Problems Verify that the licensee is identifying permanent plant modification issues and problems related to 10 CFR 50.59 applicability determinations, screenings and evaluations, and entering them in the corrective action program. For a selected sample, evaluate appropriateness of corrective actions. See IP 71152 for additional guidance.

71111.17-03 RESOURCE ESTIMATE The inspection procedure is estimated to take 172 to 212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> for the triennial review.

The triennial reviews should be performed by engineering specialists knowledgeable in the affected subject areas.

71111.17-04 COMPLETION STATUS Inspection of the minimum sample size will constitute completion of this procedure in the RPS. That minimum sample size will consist of the review of 6 to 12 licensee evaluations required by 10 CFR 50.59, 12 to 25 changes, tests, or experiments that were screened out by the licensee, and 5 to 15 permanent plant modifications.

Issue Date: 10/31/08 3 71111.17

71111.17-05 REFERENCES Inspection Procedure 71111.18, APlant Modifications@

Inspection Procedure 71152, AIdentification and Resolution of Problems@

NRC Inspection Manual Part 9900, A10 CFR 50.59 Changes to Facility, Procedures, and Tests(Experiments).@

10 CFR 50.59, AChanges, tests, and experiments.@

NRC Regulatory Guide 1.187, AGuidance for Implementation of 10 CFR 50.59, Changes, Test, and Experiments,@ Rev. Nov 2000.

NEI 96-07, Revision 1 (Nov 2000), Guidance for 10 CFR 50.59 Implementation.

END Issue Date: 10/31/08 4 71111.17

ATTACHMENT 1 Revision History for IP 71111.17 Commitment Issue Date Description of Change Training Training Comment Resolution Tracking Needed Completion Accession Number Number Date NA 01/31/08 New inspection procedure (IP) which No NA ML080250279 CN 08-005 combines the previous IP 71111.02, AEvaluations of Changes, Tests, or Experiments,@ and the biennial portion of IP 71111.17, APermanent Plant Modifications@ as a triennial inspection.

NA 10/31/08 Revise to include consideration of No N/A N/A CN 08-031 GSI-191 issue related to potential sump blockage.

Issue Date: 10/31/08 Att1-1 71111.17

SCE ATTACHMENT 17

SCE ATTACHMENT 18 San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN function as required by the specifications. The vibration levels are monitored during this test.

Evidence of the pumps operating near a critical speed would be noted as excessive vibration.

Full scale seal testing is performed at rated pressure, temperature, water chemistry, and speed to demonstrate the capability of the seals to satisfactorily perform their design function.

5.4.2 STEAM GENERATORS 5.4.2.1 Design Bases The two steam generators are designed to transfer 3458 MWt from the RCS to the secondary system, producing approximately 15.176 x 106 lb/h of 833 lb/in.2a saturated steam, when provided with 442°F feedwater. The saturated steam pressure of 833 psia is the best estimate pressure at the steam generator outlet nozzle with the reactor coolant inlet temperature at 598 °F, reactor coolant best estimate flow rate, 0% tubes plugged and an assumed tube fouling factor.

The actual steam outlet pressure will vary depending on the actual values of these parameters during plant operation. Moisture separators and steam driers in the shell side of the steam generator limit the moisture content of the steam to 0.10 wt% during normal operation at full power. The steam generator design parameters are listed in table 5.4-4. The steam generators, including the tubes, are designed for the RCS transients listed in paragraph 3.9.1.1 so that the code allowable stress limits are not exceeded for the specified number of cycles. All transients have been established based on conservative assumptions of operating conditions in consideration of supportive system design capabilities. The steam generators are capable of sustaining the following additional design transients without exceeding code allowable stress limits:

A. Ten primary side hydrostatic tests with the primary side pressurized to 1.25 times the design pressure and the secondary side at atmospheric pressure.

B. Ten secondary side hydrostatic tests with the secondary side pressurized to 1.25 times the design pressure and the primary side at atmospheric pressure.

C. Two hundred primary side leak tests with the primary side at the operating pressure of 2250 lb/in.2a and the secondary side at atmospheric pressure.

D. Two hundred secondary side leak tests with the secondary side at 900 lb/in.2a and the primary side at atmospheric pressure.

E. Fifteen thousand cycles of adding 40°F feedwater at 820 gal/min to the steam generators through the main feedwater nozzle when at hot standby conditions (normal condition). The basis is nominal operating conditions assuming intermittent feeding of the steam generators.

F. Eight cycles of adding 40°F feedwater at 700 gal/min to the steam generator after a loss of normal feedwater. This is based on the quantity of water needed to bring the 5.4-18 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN plant to shutdown cooling initiation temperature with intermittent feeding between the low water level and normal water level.

G. Four thousand pressure transients of 85 lb/in.2 across the primary divider plate in either direction caused by starting and stopping reactor coolant pumps (normal condition).

5.4-19 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN Table 5.4-4 STEAM GENERATOR PARAMETERS(a)

Parameter Value Number of SGs per plant unit 2 Heat transfer rate, each, Btu/h 5.900 x 109 Primary side Design pressure/temperature, lb/in.2a/°F 2500/650 Coolant inlet temperature, °F 598.0 Coolant outlet temperature, °F 541.3 Coolant flow rate, each, lb/h 79.79 x 106(b)

Coolant volume at 68°F each, ft3 2003 Tube size, OD, in. 0.75 Tube thickness, nominal, in. 0.0429 Secondary side Design pressure/temperature, lb/in.2a/°F 1100/560 Steam pressure at steam nozzle outlet lb/in.2a 833(b)

Steam flowrate (with 0.10% moisture), lb/h 7.588 x 106(b)

Feedwater temperature at full power, °F 442(b)

Moisture carryover, by weight (maximum), % 0.10 Primary inlet nozzle, No./ID, in. 1/42 Primary outlet nozzle, No./ID, in. 2/30 Steam nozzle, No./ID, in. 1/38 Feedwater nozzles, No./NPS/schedule 1/18/100 Overall heat transfer coefficient (estimated), Btu/hr-ft2-°F 1280 Normal Blowdown flow, lb/hr 0.155 x 106 (a)

The steam generators are qualified to operate in the Thot range from 598 to 611°F, which corresponds to the Tcold range from 541.3 to 555.4 °F.

(b)

The values of these parameters represent the best estimate values for a single steam generator based on full power operation with the reactor coolant inlet temperature at 598°F, 0% tubes plugged and an assumed tube fouling factor. The actual values of these parameters may be different than these listed in the table, depending on the steam generator condition.

5.4-20 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN The principal ferritic materials for the fabrication of the primary coolant boundary in the steam generator were specified to ASME Code, Sections II and III, 1998 Edition through 2000 Addenda requirements. The fracture toughness results met these requirements. The specific materials for the steam generator tubes are provided in subsection 5.2.3.

The operating pressure and temperature limits for the steam generator primary side were determined in accordance with 10CFR50 Appendix G, and the ASME Code,Section III, Appendix C.

The materials used on the secondary side of the steam generator were ordered to ASME Code, Sections II and III, 1998 Edition through 2000 Addenda. The operating pressure and temperature limits for the steam generator secondary side are addressed in Section 10.3.6.1.

The method of fastening tubes to the tube sheet conform with the requirements of ASME Code, Sections III and IX. Tube expansion into the tube sheet is total with no voids or crevices occurring along the length of the tube in the tube sheet. Tube supports are of the plate type with broached trefoil flat-land tube holes which provides no crevice or low flow areas that might promote accumulation of the corrosion products.

The steam generator was designed to ensure that critical vibration frequencies are well out of the range expected during normal operation and during abnormal conditions. The tubing and tubing supports are designed and fabricated with considerations given to both secondary side flow induced vibration and reactor coolant pump induced vibrations. In addition, the steam generator assemblies are designed to withstand the blowdown forces resulting from the severance of the steam nozzle. The steam generator assemblies are also designed to withstand the severance of any one of the feedwater nozzles. The two accidents are not considered simultaneously.

Discussion of the techniques used to maintain cleanliness during final assembly and shipment are discussed in subsection 5.2.3 and appendix 3A.

Onsite cleaning and cleanliness control procedures for the steam generator are consistent with the recommendations of Regulatory Guide 1.37, Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants and ANSI N45.2-1973, Cleaning of Fluid Systems and Associated Components For Nuclear Power Plants.

5.4.2.2 Description The steam generator is a recirculating, vertical U-tube type heat exchanger converting feedwater into saturated steam. The steam generator vessel pressure boundary is comprised of the channel head, lower shell, middle shell, transition cone, upper shell and upper head. The steam generator internals include the divider plate, tubesheet, tube bundle, feedwater distribution system, moisture separators, steam dryers and integral steam flow limiter installed in the steam nozzle.

The channel head is equipped with one reactor coolant inlet nozzle and two outlet nozzles. The upper vessel is equipped with the feedwater nozzle, steam nozzle and blowdown nozzle. In the channel head, there are two 18 inch access manways. In the upper shell, there are two 16 inch access manways. The steam generator is equipped with six (6) handholes and 12 inspection 5.4-21 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN ports providing access for inspection and maintenance. In addition, the steam generators are equipped with several instrumentation and minor nozzles for layup and chemical recirculation intended for chemical cleaning. The steam generator is illustrated in figure 5.4-6.

Reactor coolant enters the channel head at the bottom of each steam generator through the single inlet nozzle, flows through the U-tubes, and leaves through the two outlet nozzles. A vertical divider plate separates the inlet and outlet plenums in the channel head.

Feedwater enters the steam generator through the feedwater nozzle where it is distributed via a feedwater distribution ring. The feedwater ring is made of erosion-corrosion resistant pipe and fittings and is designed to minimize the potential for waterhammer and thermal stratification.

The feedwater is distributed at low velocity from the perforated spray nozzles mounted on the top of the feedwater ring. This design prevents foreign objects from entering the tube bundle and feedwater from impinging the surrounding components.

The feedwater leaving the spray nozzles mixes with the recirculated water and enters the downcomer, which is an annular space between the steam generator shell and a wrapper enclosing the tube bundle. At the bottom of the downcomer, the water changes the direction and enters the evaporator area, and flowing upwards picks up heat from the reactor coolant flowing in the U-tubes. The water/steam mixture exits the evaporator and enters into 38 centrifugal moisture separators. Upon leaving the separators, high quality steam enters a set of eight (8) banks of single-tier, chevron type steam dryers where its moisture content is lowered to less than 0.10% by weight at full power steam flow rate.

Impurities from the secondary side fluid are being removed by a means of continuous blowdown.

The blowdown nozzle is located in the tubesheet and serves also as a secondary side drain nozzle.

The steam generator supports are described in subsection 5.4.14. Secondary side overpressure protection is provided by 18 spring-loaded ASME Code safety valves mounted on the main steam lines as described in subsection 5.4.13.

5.4.2.3 Evaluation 5.4.2.3.1 Steam Generator Tubes 5.4.2.3.1.1 Chemistry Compatibility The steam generator, tubes are 0.75-inch OD with the wall thickness of 0.0429 wall thickness and are made of thermally treated Alloy 690. Tube sizing incorporates a general corrosion allowance that will provide for operation over the plant design lifetime. The steam generator tube support plates are made of Type 405 stainless steel. The combination of these materials and the tube support design is intended to minimize the potential for tube denting due to deposition of the general corrosion products on the tube support plates. In the San Onofre steam generators, feedwater chemistry control is an all-volatile chemistry control, which is discussed in Subsection 10.3.5 5.4-22 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN A discussion of chemistry control and corrosion control effectiveness to preclude denting is provided in subsections 10.3.5 and 10.4.5. In addition, corrosion is further inhibited by the use of condenser tubes that are made of titanium as discussed in paragraph 10.4.1.2.1.

5.4.2.3.1.2 Mechanical Considerations The reactor coolant pumps have a rotational speed of 1180 r/min, (with 1.0 specific gravity water), therefore imposition of exciting frequencies of 19 to 20 Hz and 95 to 100 Hz was considered in the steam generator design.

The low frequency range is defined as a mechanical vibration resulting from the transmission of a mechanical impulse at the frequency of pump rotation. The upper frequency range is defined as a sinusoidal pressure vibration of +/-6 lb/in.2 in the reactor coolant piping that contains the pump. The pressure variation results from the impeller vanes interacting with the cut-water vane at the volume outlet during each revolution of the impeller.

5.4.2.3.1.3 Tube Wall Thinning The extent of tube wall thinning that can be tolerated in the San Onofre steam generators without exceeding the allowable stress limits is determined by structural analysis in accordance with the requirements of the ASME Section III and USNRC R.G. 1.121. The analytical model for this analysis includes the tubes and tube supports only. The scope does not include the steam generator upper internals (moisture separators or steam dryers), because those components are not connected to the tube bundle and loads cannot be transferred from these components to the tube bundle.

The structural analysis is performed in two parts. The first part is a Functional Integrity Evaluation of a non-degraded tube with the nominal wall thickness when subjected to an upper bound plant Faulted condition loading. The resulting stresses are calculated and compared to the applicable Code allowable limits. This part of the analysis demonstrates that the non-degraded tube has a significant structural margin.

The second part of the analysis is a Degraded Tube Evaluation, in which the minimum tube wall thickness required to meet the structural requirements of R.G.1.121 is calculated. This evaluation considers: (1) wall thickness loss over the entire tube length, (2) wall thickness loss at the tube intersections with tube support plates (TSPs), and (3) wall thickness loss at the tube intersections with the anti-vibration bars (AVBs) in the tube bundle U-bend region. The minimum wall thickness is calculated for: (1) the Faulted condition, and (2) the Normal operating condition.

The more limiting of these two loading conditions determines the minimum allowable tube wall thickness. As a check to verify the acceptability of the calculated minimum wall thickness, a structural analysis is performed to demonstrate that the degraded tube with the minimum wall thickness will not burst or collapse under the conditions specified in R.G. 1.121.

5.4-23 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN The following paragraphs provide a summary of the methods of evaluation used in both parts of the structural analysis.

A. Functional Integrity Evaluation This part of the analysis evaluates overall tube integrity to show that the primary stresses in the non-degraded tube with the nominal wall thickness are within the Code allowable limits. The tube primary membrane and bending stresses are evaluated under the Faulted condition, which considers a limiting combination of the design basis events - loss of coolant accident (LOCA),

design bases earthquake (DBE) and steam line break (SLB). In this case, the SLB is conservatively represented by the pressure differential resulting from the primary side being at the design pressure and the secondary side being at atmospheric pressure.

The CEFLASH computer code was originally used to perform the hydraulic dynamic analysis of the primary coolant loop during a LOCA event with the original steam generators installed in order to determine dynamic structural response of the steam generator to the impulsive loading imparted by the escaping fluid. This loading was calculated at various original steam generator elevations, assuming a double-ended guillotine break in the reactor coolant cold leg piping.

For the replacement steam generators, a structural model of the tube bundle consisting of six groups of tubes in the upper part of the bundle (the top two tube support spans plus the U-bend) and two straight tube assemblies in the lower part of the bundle is generated using the ANSYS computer code. Using this model, the seismic and LOCA rarefaction analysis is performed. For the seismic analysis, the seismic response spectra developed for the replacement steam generators are used. For the rarefaction wave analysis, the pressure-time history (dynamic loadings) previously developed for the original steam generators (as described in the paragraph above) is used. For stress calculation, the maximum seismic and LOCA rarefaction wave loads are combined using the square-root-of-the-sum-of-the-squares (SRSS) method.

In this analysis, the SLB event is conservatively modeled by assuming the primary side being at the design pressure, plus the pressure relief valve accumulation, and the secondary side being at atmospheric pressure, and applying this pressure differential as a step function. The pressure stresses calculated based on this differential pressure are added directly to the combined stresses due to the seismic and LOCA loads.

The resulting tube primary stresses are then compared to the Code allowable stress limits for the Faulted Condition.

B. Degraded Tube Evaluation The degraded tube evaluation is performed in accordance with the requirements of R.G. 1.121 by first calculating the minimum tube wall thickness required to meet the Code allowable stress limits for the limiting plant condition. The limiting plant condition is the Normal operating condition (due to the lowest allowable) and this condition is the basis for establishing the minimum degraded tube wall thickness.

5.4-24 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN The calculations are performed in accordance with the R.G.1.121 requirement that the margin of safety against tube rupture under normal operating conditions be no less than 3 at any tube location where defects have been detected.

For any tube size and material, the minimum wall thickness required to meet the Code allowable stress limits depends on the pressure differential across the tube wall. For the purpose of this analysis, the highest expected primary-to-secondary pressure differential under the Normal operating condition is used for conservatism. This pressure differential is based on the lowest steam generator secondary pressure, which is expected to occur at the steam generator end-of-life.

The minimum wall thickness calculations consider a case where the tube wall is uniformly thinned along its entire length. This case is limiting and is the basis for establishing the minimum tube wall thickness. In addition, two other cases are evaluated for future reference. These cases are for limited axial length degradation at two distinct locations where tube thinning is most likely to occur - at the TSP intersections and at the AVB intersections. According to NUREG/CR-0718, tubes with shorter degradation lengths have higher burst pressures. The length-to-burst pressure relation from this reference is used to calculate the minimum wall thickness for these additional cases.

The degraded tube (having the minimum wall thickness calculated as described above) is evaluated against the allowable stress limits for primary membrane plus bending (in-plane) stress intensity in the straight leg region (including TSP intersections) and in the U-bend region (at AVB intersections). The stresses at the degradation locations are calculated by multiplying the stresses for the non-degraded tube by the ratio of the corresponding section properties of the nominal and degraded tube.

The resulting tube primary stresses are then compared to the Code allowable stress limits for the Faulted condition to demonstrate that the degraded tube will not burst under this worst case loading.

The degraded tube is also evaluated against collapse under the maximum possible secondary-to-primary pressure differential during a LOCA. For this purpose, calculations are performed for an ovalized tube, as the collapse pressure for such tubes is lower than for the perfectly round tubes.

C. Summary of Results The results of the functional integrity evaluation indicate that for the non-degraded tube with a nominal wall thickness of 0.0429 inch under the hypothetical combined loading resulting from LOCA+DBE+SLB, the maximum stress intensity occurs at the uppermost TSP and is 35.1 ksi.

This stress intensity compares favorably with the Code primary membrane plus bending stress allowable of 75.4 ksi for the Faulted condition. The primary-to-secondary pressure differential used to model the SLB event was conservatively taken as 2560 psid, which is the primary side at the design pressure of 2500 psia plus the 3% primary side relief valve accumulation, and the secondary side at atmospheric pressure.

5.4-25 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN The results of the degraded tube evaluation indicate that the minimum allowable tube wall thickness is 0.01923 inch for uniform degradation along the entire tube length. This result applies to any tube bundle region, straight leg or U-bend, where degradation axial length is 1.5 inch, or greater. For the TSP intersection, where the degradation length is assumed to be equal to the thickness of the TSP (1.38 inch), the minimum wall thickness is 0.01895 inch. For the AVB intersection, where the degradation length is assumed to be equal to the average tube-to-AVB contact length, the minimum wall thickness is 0.01526 inch. Therefore, the degraded tube minimum wall thickness is conservatively taken as 0.01923 inch, which corresponds to 55.17%

tube wall thinning.

The stress evaluation indicates that the degraded tube with a minimum wall thickness of 0.01923 inch, under the hypothetical combined loading resulting from LOCA+DBE+SLB (2560 psid),

will have a maximum stress intensity of 46.5 ksi in the straight leg (at the uppermost TSP) and 45.6 ksi at the limiting U-bend location. These stress intensities compare favorably with the Code allowable limits for the Faulted condition of 73.2 and 74.3 ksi, respectively.

The ASME Code criterion for tube collapse is that maximum pressure differential across the tube wall be no greater than 90% of the pressure gradient that the degraded tube has to withstand without collapsing. The maximum calculated secondary-to-primary differential pressure during a LOCA for San Onofre steam generators is 931 psid. This means that the minimum differential pressure that the degraded tube is required to withstand without collapsing is 1035 psid. Based on the test data, the differential pressure required to collapse a uniformly degraded tube with the minimum wall thickness of 0.01923 in. and the ovality of 2.8% (the maximum ovality specified for the replacement steam generators) is 1210 psid. This compares favorably with the above Code criterion.

In conclusion, a degraded tube with a minimum wall thickness of 0.01923 inch over its entire length meets the ASME Code general primary membrane stress criteria, which ensure that such a tube satisfies the requirements of R.G.1.121.

In addition to the above analyses, the following criteria from Reference 3 must be met in determining the allowable tube thinning:

1. Tubes with detected acceptable defects will not be stressed during the full range of normal reactor operation beyond the elastic range of tube material.

2. Crack-type defects that could lead to tube rupture either during normal operation or under postulated accident conditions are not acceptable.

When evaluating against the above criteria for San Onofre steam generator geometry and operating conditions, tube thinning of 55% is allowable for all tubes.

In establishing the Technical Specification limits for Units 2 and 3 tube inspections, the NRC imposed an across the board 20% reduction in the allowable tube thinning. Half of this reduction accounts for tube continuous degradation growth during the operational cycle prior to the next inspection. The other half of this reduction accounts for the accuracy of the wall thinning 5.4-26 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN measurement technique. Based on the above, the Technical Specification tube plugging limit for San Onofre Units 2 and 3 is set at 35%.

5.4.2.3.2 Potential Effects of Tube Rupture The steam generator tube rupture incident is a penetration of the barrier between the RCS and the main steam system. The integrity of this barrier is significant from the standpoint of radiological safety in that a leaking steam generator tube would allow for the transfer of reactor coolant into the main steam system. Radioactivity contained in the reactor coolant would mix with water in the shell side of the affected steam generator. This radioactivity would be transported by steam to the turbine and then to the condenser or directly to the condenser via the steam dump bypass system. Non-condensable radioactive gases in the condenser would be removed by the main condenser evacuation system and discharged to the plant vent stack. Analysis of a steam generator tube rupture incident, assuming complete severance of a tube, is presented in section 15.6.

Experience with the nuclear steam generators indicates that the probability of complete severance of a tube is remote. The strength of the material used to fabricate the steam generator tubes ensures that a double-ended tube rupture is extremely unlikely. The more probable modes of failure, which result in smaller penetrations, are those involving the occurrence of wear pinholes or small cracks in the tubes, and of cracks in the seal welds between the tubes and tube sheet. Detection and control of steam generator tube leakage is described in subsection 5.2.5.

5.4.2.3.3 Composition of Secondary Fluid The concentration of radioactivity in the secondary side of the steam generators is dependent upon the concentration of radionuclides in the reactor coolant, the primary-to-secondary leak rate, and the rate of steam generator blowdown. The expected specific activities in the secondary side of the steam generators during the periods of normal operation are given in table 11.2-27.

Activities are based on operations with average defective fuel cladding, a total primary-to-secondary leakage of 100 lb/day, and 60 gal/min blowdown rate to the blowdown processing system. An evaluation of the shell side radioactivity is presented in section 11.2.

Limits for radioactivity levels in the secondary side of the steam generators and the bases for these limits are provided in the Technical Specifications.

The recirculation water within the steam generators will contain volatile additives necessary for proper chemistry control. These and other chemistry considerations of the main steam system are discussed in subsection 10.3.5.

5.4.2.3.4 Tube Support Plate Thinning The tube supports are made of Type 405 stainless steel which eliminates the possibility of support plate thinning due to general corrosion.

5.4-27 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN 5.4.2.3.5 Tube Repair The periodic inspections of steam generator tubes result in certain tubes that exceed established criteria for remaining in service. These tubes will be removed from service by plugging.

5.4.2.3.6 Nozzle Dams Access for tube inspection and repair during a refueling outage is provided by installing seals, known as steam generator nozzle dams, in the hot leg and cold leg nozzles. With the primary head isolated from the rest of the RCS, the inside of the steam generator may be kept dry while the RCS water level is returned to the refueling level.

The nozzle dam system is comprised of an elastomeric diaphragm supported by interlocked aluminum dam segments, which are installed in the mounting grooves integral to the channel head nozzles. Leakage of RCS water is prevented by two redundant inflatable seals and one passive emergency seal. RCS venting configurations are controlled to ensure that the effective vent area is sufficient to prevent overpressurization of dams. The aluminum dam segments and latching mechanism are designed to withstand the highest RCS pressure that might be generated in the unlikely event that shutdown cooling were lost while the dams are installed.

5.4.2.4 Tests and Inspections 5.4.2.4.1 Fabrication Tests and Inspections The steam generator is tested in accordance with ASME Boiler and Pressure Vessel Code,Section III. The following nondestructive tests, some of which were not required by the code, were performed during fabrication.

5.4-28 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN Components Test(a)

Tube-sheet forging UT, MT, PT Tubesheet Cladding UT, PT Channel Head Forging UT, MT Channel Head Cladding UT, PT Secondary Shell and Head Forging UT, MT Tubes UT, ET Nozzles End (Forging) UT, MT Studs UT, MT Welds Shell, circumferential RT, MT, UT Cladding UT, PT Nozzles to shell MT, UT, PT Tube-to-tube sheet PT Instrument connections MT All welds - after hydrostatic test MT Nozzle safe ends RT, (MT or UT)

Level Taps MT (a)

UT = Ultrasonic testing MT= Magnetic-Particle testing RT = Radiographic testing PT = Liquid-penetrant testing ET = Eddy-current testing During design and fabrication of the steam generator, additional operations beyond the requirements of the ASME Boiler and Pressure Vessel Code,Section III, were performed by the vendor. These included ultrasonic testing for defects in tube sheet clad and ultrasonic testing of weld clad for bond integrity.

Initial hydrostatic tests of the primary and secondary sides of the steam generator are conducted in accordance with ASME Code,Section III. Leak tests are also performed. Following satisfactory performance of the hydrostatic tests, magnetic-particle inspections are made on all accessible welds.

Steam generator performance is further verified during the initial startup tests. Provisions for onsite cleaning and cleanliness control are described in subsection 5.2.3.

5.4-29 Rev: 32

San Onofre 2&3 FSAR Updated COMPONENT AND SUBSYSTEM DESIGN 5.4.2.4.2 Steam Generator Inservice Inspection 5.4.2.4.2.1 Preservice Examination As stated in subsection 5.2.4, the preservice examination for Class 1 steam generator components complies with the requirements of ASME Section XI, 1998 Edition through 2000 Addenda.

The preservice and inservice inspection programs for examining steam generator tubes were consistent with the recommendation of Regulatory Guide 1.83, Revision 1. The preservice examination requirements for steam generator tube inspection have been adequately met and all unacceptable defects were eliminated in accordance with ASME Section III.

5.4.2.4.2.2 Inservice Inspection The ASME Section XI Code inservice inspection (ISI) requirements for the Class 1 primary side of the Steam Generators in Units 2 and 3 are defined in subsection 5.2.4. The specific examination and pressure test requirements are defined in the ISI Program Plans for the inspection intervals.

5.4.3 REACTOR COOLANT PIPING 5.4.3.1 Design Basis The reactor coolant loop piping is designed and analyzed for normal operation and all transients discussed in subsection 3.9.1 and the following additional requirement. During heatup and cooldown of the plant, the allowable rate of temperature change for the surge line is increased to 200°F/h as a design requirement specified in paragraph 3.9.1.1. Loading combinations and stress criteria associated with faulted conditions are presented in paragraph 3.9.3.1. In addition, certain nozzles are subjected to local transients that are included in the design and analysis of the areas affected. Thermal sleeves were installed in the surge nozzle, safety injection nozzles, and charging nozzle to accommodate these additional transients. Surge line and safety injection thermal sleeves are not required for the nozzle to meet the design stress requirements and some are no longer installed. Principal parameters are listed in table 5.4-5. The ASME code and addenda the piping is designed to is specified in subsection 5.2.1.

In addition to being specified as Seismic Category I, the following additional vibratory piping assemblies are designed so that no damage to the equipment is caused by the frequency ranges of 19 to 20 Hz and 95 to 100 Hz. The definitions of these frequencies are the same as for the steam generator. Additional presentation relating to seismic and dynamic analysis and criteria for the reactor coolant piping is contained in subsections 3.7.2 and 3.9.2, respectively.

5.4-30 Rev: 32

Reference SO123-XXX-5.2 UFSAR/UFHA/DSAR CHANGE REQUEST Page 1 of 3 A. IDENTIFICATION Change Notice No.: D0061076 Unit 2 (Unique ID from SCASE)

Title:

Component and Subsystem Design Date Prepared: 05/04/2012 Document Affected: UFSAR Section/Rev. No.: 5.4 / Rev. 32 Orig. Organization: DEO Originator: J. Oikawa Originating Design Document(s) or Other: NECP 800873488 Operating License/TS affected? X No Yes Section:

Status of Change Final X Pending implementation / Approval of U2 NECP 800873488 B. DESCRIPTION Describe Why Change is Necessary (Attach additional pages as required):

Update UFSAR Section 5.4.2.3.5 with regards to proactive RSG tube plugging and stabilization in accordance with Technical Specification 5.5.2.11, SG Program SO23-SG-1 and Specification for Steam Generator Outage Services SO23-617-018 Summary of Change (Attach additional pages and/or marked up pages as required): It is necessary to proactively plug tubes located in areas that are susceptible to wear or excessive vibration.

See attached pages C. Prior NRC approval consideration per 10CFR50.59 [15]

10 CFR50.59 N/A document justification X Reference 800873488-0100 Screen or Evaluation 800589922-0060 10 CFR 50.59 Review Required Notification Number Justify Why 10 CFR 50.59 Screen or Evaluation is N/A (Attach additional pages as required):

D. SITE PROGRAM/PROCEDURE IMPACT (stand-alone changes only)

No Yes Notification Number N/A LI(123) 2 Rev 3 02/11 [

REFERENCE:

SO123-XXX-5.2]

Reference SO123-XXX-5.2 UFSAR/UFHA/DSAR CHANGE REQUEST (Continued) Change Notice D0061076 Page 2 of 3 E. TECHNICAL REVIEW:

An optional technical review may be requested by the Originator, Section Owner, or Section Owner Supervisor. No qualifications are required to perform this review which is based upon technical expertise.

(Mark N/A in Reviewed By blank if not used.)

K. Vergara* 05/04/12 A. Matheny 05/13/12 N/A Reviewed By Date Reviewed By Date Reviewed By Date F. APPROVED BY:

The following Originator signature (*electronic signature in SAP) requires T49911.

J. Oikawa* Qualifications Verified By KV / 05-04-2012 Originator Date Initials/Date The following Section Owner signature (*electronic signature in SAP) requires 1) T49912, 2) T49911, or

3) PQS 233773 (applicable to UFSAR Chapter 17 changes only).

J. Chan* Qualifications Verified By KV / 05-04-2012 Section Owner Date Initials/Date The following Section Owner Supervisor signature (*electronic signature in SAP) requires 1) T49912,

2) T49911, or 3) PQS 233773 (applicable to UFSAR Chapter 17 changes only).

R.T. Benson* Qualifications Verified By KV / 05-04-2012 Section Owner Supervisor Date Initials/Date The following UFSAR Program Manager or designee signature (*electronic signature in SAP) requires

1) T49912 or 2) T49911.

B. Rausch* Qualifications Verified By KV / 05-04-2012 UFSAR Program Manager Date Initials/Date The following NRA signature (electronic signature in SAP) [Manager, Plant Licensing or designee]

requires

1) T49912 or 2) T49911.

D. Evans* Qualifications Verified By KV / 05-04-2012 Performed By NRA Date Initials/Date G. FORWARD TO CDM-SONGS LI(123) 2 Rev 3 02/11 [

REFERENCE:

SO123-XXX-5.2]

UFSAR/UFHA/DSAR CHANGE REQUEST (Continued) Change Notice D0061076 Page 3 of 3

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY 15.6.3.2 Steam Generator Tube Rupture 15.6.3.2.1 Identification of Causes and Frequency Classification The estimated frequency of a steam generator tube rupture with or without a concurrent loss of normal AC power (LOAC) classifies it as a limiting fault incident as defined in reference 1 of section 15.0. The worst case of an SGTR with LOAC is presented below. The steam generator tube rupture accident is a penetration of the barrier between the RCS and the main steam system and results from a failure of a steam generator U-tube. In terms of break size, the worst case is a postulated double-ended tube rupture. Experience with nuclear steam generators indicates that the probability of complete severance of the Inconel vertical U-tubes is remote. No such double-ended rupture has ever occurred in a steam generator of this design. The more probable modes of failure result in considerably smaller penetrations of the pressure barrier. They involve the formation of etch pits or small cracks in the U-tubes or cracks in the welds joining the tubes to the tube sheet.

In accordance with the direction given in Sections 15.0 & 15.0.7, additional information which completes the presentation of this event is provided in Section 15.10.6.3.2.

15.6.3.2.2 Sequence of Events and Systems Operations Integrity of the barrier between the RCS and main steam system is significant from a radiological standpoint since a leaking steam generator tube would allow transport of reactor coolant into the main steam system. Radioactivity contained in the reactor coolant would mix with shellside water in the affected steam generator. During normal plant operations, some of this radioactivity would be transported through the turbine to the condenser where the noncondensible radioactive materials would be released via the condenser air ejectors.

Since the plant is operating at 100% power for approximately 16 minutes before the effects of the primary-to-secondary leak cause the reactor trip, the radioactivity concentration in the steam generators is allowed to increase before the steam generator safety valves open releasing radioactive materials to the atmosphere.

Following the tube rupture, the RCS pressure would gradually decrease. The primary-to-secondary leak rate and drop in RCS pressure would result in all CVCS charging pumps being brought on line and reactor trip due to low pressurizer pressure. Following reactor trip, the main steam system pressure would increase to the point where the turbine bypass valves would open to control the main steam system pressure. If turbine bypass is unavailable, the steam generator safety valves would open to control the main steam system pressure. The operator can isolate the damaged steam generator and cool the NSSS using manual operation of the auxiliary feedwater and the atmospheric steam dump valve of the unaffected steam generator any time after reactor trip occurs. The analysis presented herein conservatively assumes that operator action is delayed until 30 minutes after first indication of the event.

15.6-11 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Diagnosis of this accident would be facilitated by radiation monitors in the blowdown sample lines from each steam generator, in the blowdown processing system neutralization sump discharge sea line which processes blowdown from both steam generators, in the condenser air ejector discharge line, and adjacent to the main steam lines. These monitors would initiate alarms in the control room and inform the operator of abnormal activity levels and that corrective action is required.

Behavior of the systems varies depending upon the size of the rupture. For leak rates up to the capacity of the charging pumps in the CVCS, reactor coolant inventory can be maintained and an automatic reactor trip would not occur. During the first 30 minutes of the accident, a reactor trip is not necessary because the safety limits are not approached and there is no danger of violating dose limits. The 30-minute interval is a conservative time period based on the availability of alarms and indications. The Technical Specifications specify plant shutdown within 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of detection for leaks greater than 1 gal/min. In addition, the plant emergency procedures will provide for rapid plant shutdown based on operator action in the event of a tube failure.

Assuming a 30-minute operator action interval, the operator can then take action to ramp down the plant or to manually trip the reactor and place the plant in cold shutdown. Under these operating conditions, the gaseous fission products would be released from the main steam system at the condenser air ejector discharge until the shutdown cooling system is initiated.

For leaks that exceed the capacity of the charging pumps, pressurizer water level and pressurizer pressure decrease and a reactor trip results.

Table 15.6-5 gives a sequence of events which occur following a steam generator tube rupture with concurrent loss of normal AC power.

15.6.3.2.3 Core and System Performance A. Mathematical Model The NSSS response to a steam generator tube rupture with concurrent loss of normal AC power was simulated using the CESEC computer program described in section 15.0. The thermal margin on DNBR in the reactor core was simulated using the TORC computer program described in section 15.0 with the CE-1 CHF correlation described in chapter 4.

B. Input Parameters and Initial Conditions The input parameters and initial conditions used to analyze the NSSS response to a steam generator tube rupture with concurrent loss of normal AC power are discussed in section 15.0. In particular, those parameters which were unique to the analysis discussed below are listed in table 15.6-6.

The initial conditions for the principal variables monitored by the core operating limit supervisory system (COLSS) were varied over the reactor operating space given in 15.6-12 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY table 15.0-5 to determine the set of conditions which would produce the most adverse consequences following a steam generator tube rupture with a concurrent loss of normal AC power. Various combinations of initial core inlet temperature, core inlet flowrate, and pressurizer pressure were considered. In addition, the scram reactivity used was consistent with the axial power distribution used. Decreasing the initial core inlet temperature increases the primary-to-secondary leak rate and integrated leak, but reduces the releases via the steam generator safety valves. Since the steam generator pressure and temperature are initialized at lower values, a point is reached where the steam generator can increase and peak without opening the steam generator safety valves. Decreasing the RCS pressure hastens the low pressurizer pressure reactor trip, but results in lower releases due to a lower leak rate. Therefore the initial RCS pressure assumed, which is in fact outside the space given in table 15.0-5, ensures that the results are conservative. Increasing the core inlet flowrate produces faster energy transport through the RCS and results in an increased leak rate and higher releases from the steam generator safety valves. Varying the primary-to-secondary break size can produce a case showing higher offsite dose for a break size smaller than that equivalent to a double-ended rupture. For break sizes resulting in a reactor trip during the first 30 minutes of the incident (see emergency procedures), the initial leak rate decreases from that value equivalent to a double-ended rupture, and the offsite dose also decreases due to the drop in the integrated leak. The decrease in break size also delays the time of reactor trip. As the break size is decreased further, the integral leak is reduced for the 30-minute operator action interval, and, therefore, the radiological consequences will be less severe. For the smaller breaks sizes, the following information is still available to the operator:

1. Radiation monitors

2. Difference in steam generator water levels or feedwater flowrates if the automatic steam generator control is being used

3. All CVCS charging pumps on

4. Drop in RCS pressure 15.6-13 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-5 SEQUENCE OF EVENTS FOR THE STEAM GENERATOR TUBE RUPTURE WITH CONCURRENT LOSS OF NORMAL AC POWER Time Setpoint (seconds) Event or Value 0.0 Tube rupture occurs ----

520.6 Pressurizer heaters de-energized, ft3(8.9 ft below 100% power 334 operating level) 985.1 Low pressurizer pressure boundary trip signal generated by the 1,785 CPC, turbine stop valves close, loss of normal AC power, psia 985.5 CEAs begin to drop into core ----

991.3 No. 2 steam generator safety valves begin to open, psia 1,089 991.6 No. 1 steam generator safety valves begin to open, psia 1,089 995.3 Maximum No. 1 steam generator pressure, psia 1,131 995.3 Maximum No. 2 steam generator pressure, psia 1,131 1,000.0 Pressurizer empties ----

1,010.2 Safety injection actuation signal, psia 1,560 1,020.9 Low steam generator level signal, lbs (27.027 ft. above 134,540 tubesheet) 1,073.8 Auxiliary feedwater flow initiated ----

1,305.6 No. 2 steam generator safety valves close, psia 926(a) 1,305.6 No. 1 steam generator safety valves close, psia 926(a) 1,800.0 Operator isolates damaged steam generator and opens ----

atmospheric steam dump valve to the unaffected steam generator to begin plant cooldown to shutdown cooling 11,242.0 Shutdown cooling initiated, (F 350 (a) The original accident analysis assumed 4% main steam safety valve blowdown. Blowdown for current valve ring settings is bounded by 15% (see Section 15.0). The increased blowdown affects the MSSV steam releases during the first 30 minutes of the accident. The evaluation of radiological consequences was revised to include the effect of increased MSSV blowdown. The conclusions of the analysis remain valid. The doses are a small fraction of 10CFR100 exposure guidelines.

15.6-14 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-6 ASSUMPTIONS FOR THE STEAM GENERATOR TUBE RUPTURE WITH CONCURRENT LOSS OF NONEMERGENCY AC POWER ANALYSIS Parameter Assumption Initial core power level, MWt 3,478 Core inlet coolant temperature, (F 553 Core mass flowrate, 106 lbm/hr 154.3 Reactor coolant system pressure, psia 2,400 Steam generator pressure, psia 900 Moderator temperature coefficient, 10-4 'k/k/(F -3.3 Doppler coefficient multiplier 0.85 CEA worth for trip, %U -6.0 Steam bypass control system Inoperative Feedwater regulating system Inoperative 15.6-15 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY

5. Rapid drop in the volume control tank level Based on this information, the operator can ramp down or manually trip the reactor if a trip has not occurred within the initial 30 minutes. In so doing, releases to the site boundary will be limited because of the relatively lower concentration in the steam generators.

The following assumptions and parameters are used to calculate the activity releases and offsite doses for a steam generator tube rupture (SGTR):

(a) The RCS equilibrium activity is based on long-term operation at 105% of the ultimate core power level of 3390 MWt (3390 MWt x 1.05 = 3560 MWt) with 1% failed fuel.

These activities are given in table 11.1-2. See paragraph 15.6.3.2.5 items B and C for a discussion on iodine spikes.

(b) The steam generator equilibrium activity for both steam generators is assumed to be 0.1 Ci/g dose equivalent I-131 (Technical Specification limit) prior to the accident.

(c) Offsite power is lost; the main condenser is not available for steam relief via the turbine bypass system.

(d) Following the accident, no additional steam and radioactivity are released to the environment when the shutdown cooling system is placed in operation (3.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />).

(e) There is no main condenser evacuation system release and no steam generator blowdown during the accident.

(f) Only one steam generator is affected.

(g) The amount of noble gas activity released is equal to the amount present in the reactor coolant discharged into the secondary side following the tube rupture. The amount of noble gas activity contained in the secondary system is negligible in comparison.

(h) Iodine activity released is based on the equilibrium activity present in the steam generators (0.1 Ci/g dose equivalent I-131) and the amount of activity present in the reactor coolant discharged into the affected steam generator.

(i) Thirty minutes after the accident, the affected unit is isolated. No steam and fission product activities are released from the affected steam generator thereafter.

(j) The total amount of discharge of reactor coolant into the secondary system through the rupture is 75,672 pounds (in 30 minutes).

15.6-16 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY (k) The post-accident partition coefficient of 0.1 was used in the steam generator between the water and steam phases.

(1) The primary-to-secondary leakage of 8640 lbm/d (1.0 gal/min) is assumed to be applicable to the unaffected steam generator. The portion of the noble gas activity from the primary-to-secondary leakage attributed to the unaffected steam generator is assumed to be released during the course of the accident (3.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />).

(m) The amount of discharge of steam from the unaffected steam generators is calculated to be 6.33 x 105 pounds and, from the affected steam generator, 5.52 x 104 pounds.

(n) The activity released from the affected and unaffected steam generators is immediately vented to the atmosphere. The release point is assumed to be the safety valve nearest the control room air intake. No credit is taken for radioactive decay for isotopes in transit to dose points.

C. Results The dynamic behavior of important NSSS parameters following a steam generator tube rupture with a concurrent loss of normal AC power are presented in figures 15.6-1 through 15.6-14.

The primary-to-secondary leakage due to a steam generator tube rupture results in a gradual decrease in the reactor coolant inventory and a gradual drop in the pressurizer level and pressure. As the level drops in the pressurizer, all charging pumps are brought on line while the letdown flow is reduced to a minimum. At approximately 15 minutes after initiation of the tube rupture, the reactor trips due to a low pressurizer pressure trip signal. The reactor trip results in the steam generator pressure rapidly increasing and opening the steam generator safety valves, since no credit is taken for the turbine bypass system. As a result of the low RCS pressure, a SIAS is also generated. As the safety injection system returns water to the RCS, the rate of RCS pressure drop decreases.

The primary system pressure and the pressurizer level in terms of water volume during the transient are shown as functions of time in figures 15.6-3 and 15.6-5, respectively. The steam generator pressure and steam generator levels in terms of liquid mass are shown as functions of time in figures 15.6-6 and 15.6-10, respectively.

On reactor trip, the loss of normal AC power is assumed to occur. As the reactor coolant pumps coast down, transfer of energy to the main steam system is reduced and the RCS pressure increases rapidly for approximately 60 psi before peaking out and commencing a more gradual drop. On reactor trip, the steam generator pressure rapidly increases, opening the steam generator safety valves. With the loss of feedwater, the steam generator pressure remains above the reseat pressure of the steam generator safety valves. The residual water inventory in the steam generators drops and initiates a low steam generator water level trip signal, which, in turn, 15.6-17 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY automatically initiates an auxiliary feedwater flow signal. With the initiation of auxiliary feedwater flow, the steam generator pressure again drops gradually and the steam generator safety valve closes. Both the primary and secondary pressure continue to drop for the remainder of the transient.

After 30 minutes, the operator has identified the steam generator with the tube rupture based on information supplied relative to the steam generator water level and has closed the main steam isolation valve and stopped auxiliary feedwater flow to the damaged steam generator and terminated atmospheric releases from that steam generator. Plant cooldown is initiated by dumping steam from the intact steam generator. After the temperature of the reactor coolant is reduced to 350(F, the operator activates the shutdown cooling system and isolates both steam generators.

The maximum RCS and secondary pressures do not exceed 110% of design pressure following a steam generator tube rupture with concurrent loss of normal AC power, thus assuring that the integrity of the RCS and main steam system is not further degraded. The minimum DNBR of greater than 1.31 indicates no violation of the fuel thermal limits.

15.6.3.2.4 Barrier Performance A. Mathematical Model The mathematical model used for elevation of barrier performance is identical to that described in paragraph 15.6.3.2.3.

B. Input Parameters and Initial Conditions The input parameters and initial conditions used for evaluation of barrier performance are identical to those described in paragraph 15.6.3.2.3.

C. Results Figure 15.6-11 gives the steam generator safety valves flowrates versus time for the steam generator tube rupture with concurrent loss of normal AC power transient. At 30 minutes when the atmospheric steam dump valve is opened, the steam generator safety valves will have discharged no more than 101,830 pounds of steam; and during the first 30 minutes while the auxiliary feedwater pumps are operating, an additional 8510 pounds of steam will have been vented to the atmosphere via the steam-driven auxiliary feedwater pump. The operator then begins a 75(F/hr cooldown requiring a steam release rate of 61.3 lbm/s through the atmospheric dump valve and the auxiliary feedwater steam turbine. Approximately 578,210 pounds of steam would be discharged through the atmospheric steam dump valve and the auxiliary feedwater steam turbine during the 2.62-hour cooldown, giving a total steam release to the atmosphere of 688,550 pounds. For the first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the combined steam release to the atmosphere is 440,120 pounds.

15.6-18 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY 15.6.3.2.5 Radiological Consequences A. Design Basis, Method of Analysis, No Iodine Spike

1. Physical Model The evaluation of the radiological consequences of a postulated steam generator tube rupture assumes a complete severance of a single steam generator tube while the reactor is operating at full rated power and a coincident loss of offsite power at the time of reactor trip. Occurrence of the accident leads to an increase in contamination of the secondary system due to reactor coolant leakage through the tube break. A reactor trip occurs automatically as a result of low pressurizer pressure at approximately 985 seconds after the tube rupture occurs. The reactor trip automatically trips the turbine.

The resulting increase in radioactivity in the secondary system is detected by radiation monitors (refer to section 11.5). The coincident loss of offsite station power causes closure of the turbine bypass valves to protect the condenser. The steam generator pressure will increase rapidly, resulting in steam discharge as well as activity release through the main steam safety valves. Venting from the affected steam generator; i.e., the steam generator, which experiences tube rupture, continues until the secondary steam pressure is below the main steam safety valve setpoint. At this time, the affected steam generator is effectively isolated, and, thereafter, no steam or activity is assumed to be released from the affected steam generator. The remaining unaffected steam generator removes core decay heat by venting steam through the atmospheric dump valve and steam-driven auxiliary turbine until cooldown can be accomplished with the shutdown cooling system.

The analysis of the radiological consequences of a steam generator tube rupture considers the most severe release of secondary activity as well as reactor activity leaked from the tube break. The inventory of iodine and noble gas fission product activity available for release to the environment is a function of the primary-to-secondary coolant leakage rate, the percentage of defective fuel in the core, and the mass of steam discharged to the environment. Conservative assumptions are made for all these parameters.

The sequence of events for this accident is presented in Table 15.6-5.

2. Assumptions and Conditions The major assumptions and parameters assumed in the analysis are itemized in Table 15.6-6.

15.6-19 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY

3. Mathematical Models Used in the Analysis Mathematical models used in the analysis are described in the following items:

(a) The mathematical model used to analyze the activity released during the course of the accident is described in appendix 15B.

(b) The atmospheric dispersion factors used in the analysis, which are based on meteorological conditions assumed present during the course of the accident, are calculated according to the model described in subsection 2.3A. For the design basis analysis, the 5% level F/Qs presented in table 15B-4 were used.

(c) The potential thyroid inhalation dose and beta-skin and total-body gamma immersion dose to an individual exposed at the exclusion area boundary or outer boundary of the low population zone (LPZ) are analyzed using the models described in appendix 15B.

(d) The buildup of activity in the control room and the potential integrated dose to control room personnel are analyzed based on models described in appendix 15B.

4. Identification of Leakage Pathways and Resultant Leakage Activity For the purposes of evaluating the radiological consequences of a postulated steam generator tube rupture, the activity released from the affected steam generator is assumed to be released directly to the environment by the safety valves until the steam generator is isolated by the operator 30 minutes after the initiation of the accident. The activity released from the unaffected steam generator is from the safety valves until the safety valves shut, and then from the auxiliary feedwater pump turbine and atmospheric dump valve during the cooldown phase until the shutdown cooling system is placed in operation. Since the activity is released directly to the environment with no credit for plateout, retention, or decay, the results of the analysis are based on the most direct leakage pathway available. Therefore, the resultant radiological consequences represent the most conservative estimate of the potential integrated dose due to the postulated steam generator tube rupture.

5. Identification of Uncertainties and Conservatisms in the Evaluation of the Results The uncertainties and conservatisms in the assumptions used to evaluate the radiological consequences of a steam generator tube rupture are as follows:

(a) Reactor coolant equilibrium activities are based on 1% failed fuel, which is greater by a factor of two to eight than that normally observed in past pressurized water reactor (PWR) operation.

15.6-20 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY (b) Steam generator equilibrium activity for both steam generators is assumed to be equal to the Technical Specification limit. The Technical Specification limits are conservatively derived based on accidents such as the SGTR.

(c) Tube rupture of the steam generator is assumed to be a double-ended severance of a single steam generator tube. This is a conservative assumption since the steam generator tubes are constructed of highly ductile materials. The more probable mode of tube failure is one of minor leaks of undetermined origin. Activity in the secondary steam system is subject to continual surveillance, and the accumulation of activity from minor leaks that exceed the limits established in the Technical Specifications would lead to reactor shutdown. Therefore, it is unlikely that the total amount of activity considered available for release in this analysis would ever be realized.

(d) The coincident loss of offsite power with the occurrence of the reactor trip following the steam generator tube rupture is a conservative assumption. In the event of availability of offsite power, the turbine bypass valves will open, relieving steam to the main condenser. This will reduce the amount of steam and entrained activity discharged directly to the environment from the unaffected steam generators.

(e) The meteorological conditions assumed to be present at the site during the course of the accident are based on F/Q values which are expected to be worse 5% of the time. This condition results in the poorest values of atmospheric dispersion calculated for the exclusion area boundary or LPZ outer boundary. Furthermore, no credit has been taken for the transit time required for activity to travel from the point of release to the exclusion area boundary or LPZ outer boundary. Hence, the radiological consequences evaluated under these conditions are conservative.

(f) A conservative steam generator partition coefficient (PC) of 0.1 is used in the cooldown phase (release to atmospheric dump valve).

B. Design Basis, Coincident (pre-existing) Iodine Spike and SGTR In this evaluation, a case of coincident iodine spike which already exists due to a previous power transient was considered. The mathematical models, assumptions, and parameters are described in paragraph 15.6.3.2.5, item A with the following exception:

The RCS inventory was assumed to be 60 Ci/g dose equivalent Iodine 131 vice the reactor coolant inventory shown in table 11.1-2 which is based on 105% of design core power and 1% failed fuel. This 60 Ci/g is the Technical Specification limit for full power operation following an iodine spike for up to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

15.6-21 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY C. Design Basis, Spike Caused by the SGTR In this evaluation, a case with an iodine spike which was caused by the reactor trip following the SGTR was evaluated for radiological consequences. The mathematical models, assumptions, and parameters used are described in paragraph 15.6.3.2.5 with the following exception:

Prior to the SGTR, the RCS activity is based on 105% of design power and 1% failed fuel. This reactor coolant inventory is the same as that used in paragraph 15.6.3.2.5.

However, at the initiation of the SGTR accident, the I-131 equivalent source term (released from fuel) is assumed to increase as discussed in paragraph 15.1.3.1B.5.3.

D. Realistic Analysis, Method of Analysis A steam generator tube rupture (SGTR) is classified as a limiting fault. This accident is not expected to occur during the life of the plant but is postulated because the consequences of a SGTR include the potential for the release of significant amounts of radioactive materials. The term "realistic analysis" as used in this section does not imply that the accident is expected to occur during the life of the plant. The term "realistic analysis" signifies that more realistic assumptions and parameters have been used to evaluate the radiological consequences of a limiting fault as defined by Revision 2 of Regulatory Guide 1.70. Major assumptions and parameters used in the realistic analysis are presented in Table 15.6-8. The radiological consequences are presented in Table 15.6-7.

15.6-22 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-7 RADIOLOGICAL CONSEQUENCES OF A POSTULATED STEAM GENERATOR TUBE RUPTURE W/LOAC (Sheet 1 of 2)

Design Basis Realistic Results Assumptions Assumptions Exclusion Area Boundary Dose (0 to 2-hour), rem No iodine spike Thyroid 3.4 3.9 x 10-4 Beta-skin 11.8 x 10-2 8.2 x 10-5 Total-body gamma 7.0 x 10-2 4.5 x 10-5 Coincident (pre-existing) iodine spike Thyroid 29.4 No spike Beta-skin 12.8 x 10-2 No spike Total-body gamma 9.7 x 10-2 No spike Iodine spike caused by accident Thyroid 18.4 No spike Beta-skin 12.4 x 10-2 No spike Total-body gamma 8.5 x 10-2 No spike LPZ Outer Boundary Dose (duration), rem No iodine spike Thyroid 10.2 x 10-2 10.1 x 10-5 Beta-skin 3.4 x 10-3 2.1 x 10-5 Total-body gamma 2.0 x 10-3 11.7 x 10-6 15.6-23 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-7 RADIOLOGICAL CONSEQUENCES OF A POSTULATED STEAM GENERATOR TUBE RUPTURE W/LOAC (Sheet 2 of 2)

Design Basis Realistic Results Assumptions Assumptions Control Room Dose (duration), rem No iodine spike Radiation External to the Control Room Total-body gamma 5.3 x 10-4 6.0 x 10-6 Radiation Internal to the Control Room Thyroid 1.2 x 10-2 2.5 x 10-5 Beta-skin 10.1 x 10-1 1.4 x 10-2 Total-body gamma 2.2 x 10-2 2.9 x 10-4 A realistic analysis of the radiological consequences of a postulated SGTR was performed.

This analysis is identical with the evaluation presented in paragraph 15.6.3.2.5 with the following exceptions:

1. Reactor coolant system inventory is based on 0.12% failed fuel vice 1% failed fuel and 100% (3390 MWt) via 105% (3560 MWt) of the ultimate core power level respectively. Isotopic inventory is presented in table 11.1-3.

2. An iodine spike, pre-existing or caused by the accident, does not occur.

3. Steam generator equilibrium activity prior to the accident is based on 100 lbm/d and 0.12% failed fuel versus the Technical Specification limit for steam generator activity.

Steam generator activity is presented in table 11.1-21 (normal case).

4. 50% level F/Qs are used instead of 5% level F/Qs.

5. A post-accident partition coefficient of 0.01 was used between the water and steam phases versus 0.1 for the design basis case.

15.6-24 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-8 PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A STEAM GENERATOR TUBE RUPTURE, W/LOAC (Sheet 1 of 4)

Design Basis Realistic Parameter Assumption Assumption Source Data Power level, MWt 3,560 3,390 Fraction failed fuel, % 1 0.12 Steam generator tube leakage, lbm/d 8,640 (1 gal/min) 100 Table of equilibrium reactor coolant activity

1. No iodine spike Table 11.1-2 Table 11.1-3

2. Coincident (pre-existing) 60 No spike iodine spike Ci/g dose equivalent I-131

3. Iodine spike caused by accident Section 15.1.3.1B.5.3(a) No spike Table of equilibrium secondary 0.1 Ci/g dose equivalent Table 11.1-2 system activity I-131 (technical (average case) specification limit)

Activity Release Data Steam discharge, lb Affected steam generator Reactor coolant leakage to 75,672 75,672 steam generator (0 to 30 min)

Mass of steam released 5.52 x 104 5.52 x 104 (a)

Prior to accident, reactor coolant activity assumed to be based on 1.0% failed fuel (table 11.1-2). Following SGTR, activity assumed to increase as discussed in section 15.1.3.1B.5.3. Iodine release terms increase by a factor of 500.

15.6-25 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-8 PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A STEAM GENERATOR TUBE RUPTURE, W/LOAC (Sheet 2 of 4)

Design Basis Realistic Parameter Assumption Assumption Unaffected steam generator 6.33 x 105 6.33 x 105 Duration of accident (3.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />)

Iodine partition coefficients for 0.1 0.01 steam generators (between water and steam phase)

Activity released from steam generators, Ci No iodine spike Isotope 0-2 hour Duration 0.2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Duration I-131 1.8(+1) 1.9(+1) 1.6(-1) 1.6(-1)

I-132 4.8(0) 5.0(0) 3.8(-2) 3.8(-2)

I-133 2.2(+1) 2.3(+1) 1.8(-1) 1.8(-1)

I-134 2.0(0) 2.0(0) 1.7(-2) 1.7(-2)

I-135 9.3(0) 9.6(0) 7.8(-2) 7.9(-2)

Xe-131m 8.3(+1) 8.4(+1) 3.8(0) 3.8(0)

Xe-133m 0 0 0 0 Xe-133 11.6(+3) 11.7(3) 6.2(+2) 6.3(+2)

Xe-135m 3.8(+1) 3.8(+1) 4.5(-1) 4.5(-1)

Xe-135 3.2(+2) 3.2(+2) 12.2(0) 12.2(0)

Xe-137 0 0 0 0 Xe-138 1.9(+1) 2.0(+1) 1.5(0) 1.5(0)

Kr-83m 0 0 0 0 Kr-85m 8.2(+1) 8.2(+1) 7.6(0) 7.7(0)

Kr-85 1.8(+2) 1.8(+2) 5.2(0) 5.2(0)

Kr-87 4.4(+1) 4.4(+1) 2.1(0) 2.1(0)

Kr-88 1.4(+2) 1.4(+2) 6.9(0) 7.0(0) 15.6-26 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-8 PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A STEAM GENERATOR TUBE RUPTURE, W/LOAC (Sheet 3 of 4)

Design Basis Realistic Parameter Assumption Assumption Coincident (Pre-existing) iodine spike Isotope 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> No iodine spike I-131 1.5(+2) No iodine spike I-132 4.2(+1) No iodine spike I-133 1.9(+2) No iodine spike I-134 1.8(+1) No iodine spike I-135 8.3(+1) No iodine spike Xe-131m 8.3(+1) No iodine spike Xe-133m 0 No iodine spike Xe-133 11.6(+3) No iodine spike Xe-135m 3.8(+1) No iodine spike Xe-135 3.2(+2) No iodine spike Xe-137 0 No iodine spike Xe-138 1.9(+1) No iodine spike Kr-83m 0 No iodine spike Kr-85m 8.2(+1) No iodine spike Kr-85 1.8(+2) No iodine spike Kr-87 4.4(+1) No iodine spike Kr-88 1.4(+2) No iodine spike Iodine spike caused by accident Isotope 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> I-131 9.4(+1) No iodine spike I-132 2.6(+1) No iodine spike I-133 11.7(+1) No iodine spike I-134 10.6(0) No iodine spike I-135 5.1(+1) No iodine spike Xe-131m 8.3(+1) No iodine spike Xe-133m 0 No iodine spike Xe-133 11.6(+3) No iodine spike Xe-135m 3.8(+1) No iodine spike Xe-135 3.2(+2) No iodine spike Xe-137 0 No iodine spike Xe-138 1.9(+1) No iodine spike 15.6-27 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Table 15.6-8 PARAMETERS USED IN EVALUATING THE RADIOLOGICAL CONSEQUENCES OF A STEAM GENERATOR TUBE RUPTURE, W/LOAC (Sheet 4 of 4)

Design Basis Realistic Parameter Assumption Assumption Isotope (continued) 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Kr-83m 0 No iodine spike Kr-85m 8.2(+1) No iodine spike Kr-85 1.8(+2) No iodine spike Kr-87 4.4(+1) No iodine spike Kr-88 1.4(+2) No iodine spike Dispersion data Distance to exclusion area boundary, 576 576 meters Distance to LPZ outer boundary, 3,140 3,140 meters Atmospheric dispersion factors, s/m3 5% level F/Q 50% level F/Q (table 15B-4) (table 15B-4)

Control room design parameters Refer to Refer to table 15B-5 table 15B-5 Table 15.6-9 (Deleted)

Table 15.6-10 (Deleted) 15.6.3.2.6 Conclusions A. Filter Loadings The only ESF filtration system considered in the analysis which limits the consequences of the SGTR is the control room filtration system. Activity loadings on the control room carbon adsorber are based on flowrate through the filter, concentration of activity at the filter inlet, and filter efficiency.

15.6-28 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated DECREASE IN REACTOR COOLANT INVENTORY Activity loading on the control room carbon adsorber has been designed for the LOCA, paragraph 15.6.3.3.5.1. Since the control room filters are capable of accommodating the potential design basis LOCA fission product iodine loadings, more than adequate design margin is available with respect to postulated steam generator tube rupture accident releases.

B. Dose to an Individual Exposed at the Exclusion Area Boundary and the Outer Boundary of the Low Population Zone.

The potential radiological consequences resulting from the occurrence of a postulated steam generator tube rupture were analyzed, using assumptions and models described in preceding subsections for both the design basis and realistic analyses.

The direct beta-skin and total-body gamma dose due to immersion and the thyroid dose due to inhalation were analyzed for the 0 to 2-hour dose at the exclusion area boundary and for the duration of the accident at the LPZ outer boundary. The results are listed in Table 15.6-8. The resultant doses are a small fraction of 10CFR100 for the design basis evaluation without iodine spike and are within 10CFR100 limits for cases considering an iodine spike.

C. Dose to Control Room Personnel Radiation doses to control room personnel following a postulated steam generator tube rupture are based on the same shielding, ventilation, cavity dilution, and dose model assumptions as those given in appendix 15B. Buildup of activity in the control room is based on the 3.12-hour release of activity following the accident. Control room personnel are subject to total-body gamma dose due to immersion in the cloud concentrations internal to the control room. The thyroid inhalation dose is based on immersion in cloud concentrations internal to the control room.

The thyroid, beta-skin, and total-body gamma doses to control room personnel are listed in Table 15.6-8. The resultant doses are within the limits of 10CFR50, Appendix A, General Design Criterion 19.

15.6.3.2.7 RCS Voiding The consequences due to potential void formation in the RCS during design basis transients are discussed in reference 2. The conclusions are that the void formation, if any, in the RCS is not great enough to impair reactor coolant circulation or core coolability, and that the impact of RCS voiding will not result in violation of NRC Standard Review Plan acceptance criteria. The conclusions reached in reference 2 are valid for the non-LOCA events, namely the steam generator tube rupture and the letdown line break presented in this section.

15.6.3.3 Loss-of-Coolant Accident (LOCA) 15.6-29 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS The offsite radiological doses for the Primary Sample or Instrument Line Break with an accident-induced iodine spike are a small fraction (i.e., do not exceed 10%) of the 10 CFR 100 exposure guidelines, and the Control Room radiological doses are within the 10 CFR 50 Appendix A General Design Criterion 19 exposure guidelines.

15.10.6.3.2 Steam Generator Tube Rupture with Concurrent Loss of AC Power Introduction A Steam Generator Tube Rupture (SGTR) event is a penetration of the barrier between the Reactor Coolant System (RCS) and the main steam system via the double-ended break of a U-tube. This causes highly radioactive RCS fluid to contaminate the secondary side. The radioactivity is released via the condenser air ejectors, the Main Steam Safety Valves (MSSVs),

and the Atmospheric Dump Valves (ADVs).

This event is analyzed with a concurrent loss of AC power, which increases the radiological release to the environment (see section 15.6.3.2.5). It is this analysis which is presented below.

If the primary to secondary leak is beyond the capacity of the charging pumps, the reactor will eventually trip on a low pressure trip signal. As a result of the loss of AC, the electrical power would be unavailable for the station auxiliaries such as the Reactor Coolant Pumps (RCPs) and the Main Feed Water (MFW) pumps. Under such circumstances, the plant would experience a simultaneous loss of load, normal feed water flow, forced reactor coolant flow and steam generator blowdown capability.

When the reactor is off line, stored energy and fission product decay energy must be dissipated by the reactor coolant and main steam systems. In the absence of forced reactor coolant flow, convective heat transfer is supported by natural circulation reactor coolant flow. Initially, the liquid inventory in the steam generators is used and the resultant steam is released to the atmosphere via the MSSVs. With the availability of stand-by power provided by the automatic start-up of the diesel generators, Auxiliary (emergency) Feed Water (AFW) flow is initiated on a low steam generator level signal.

When the reactor plant has been stabilized in Mode 3, the operator achieves plant cool down using remotely operated ADVs. The plant is cooled to 350°F at a nominal rate of 75°F/hr. At this time, Shut Down Cooling (SDC) is initiated.

The analysis of record conservatively assumes the operator action to isolate the affected steam generator is delayed until 30 minutes after initiation of the event. The operators diagnosis of the SGTR event is facilitated by the radiation monitors which initiate alarms and signal the existence of abnormal radioactivity levels.

Radiation monitors are found in the blowdown sample lines from each steam generator, in the blowdown processing system neutralization sump discharge sea line which processes blowdown from both steam generators, and in the condenser air ejector discharge line. Additional 15.10-177 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS diagnostic information is provided by RCS pressure and pressurizer level response indicating a loss of primary coolant. Level in the affected steam generator increases as the primary fluid enters the steam generator driven by the substantially higher primary pressure.

The offsite and control room dose consequences of the postulated steam generator tube rupture are analyzed for the assumed conditions of no iodine spike, a pre-accident iodine spike, and an accident initiated iodine spike in the reactor coolant.

Summary of Methods The CESEC-III code is used to simulate the transient for the first 1800 seconds (i.e., 30 minutes).

The output of the code provides the amount of primary to secondary leak, the amount of steam transported from the steam generators through the MSSVs and the overall Nuclear Steam Supply System (NSSS) response to the event. This information is then used to derive the radiological releases and accompanying doses.

This analysis is primarily performed to establish the parameters, such as the primary to secondary mass transferred during the event, by which the radiological releases are calculated.

There is no specific acceptance criteria for the mass releases.

One computer case was run for this analysis. This was an 1800 seconds CESEC-III simulation of a double-ended SGTR in the right hand (arbitrary designation) steam generator. This case utilizes a 15% MSSV blowdown model to determine the impact on steam released to atmosphere.

The primary transient analysis inputs and assumptions for the analysis are presented below in Table 15.10.6.3.2-1. The sequence of events is provided in Table 15.10.6.3.2-2.

The dose methodology for this event is described in Appendices 15B and 15.10.B. Using this methodology, design basis 0-2 hour Exclusion Area Boundary, 0-30 day Low Population Zone, and 0-30 day Control Room doses were calculated with and without consideration of pre-existing and accident induced iodine spikes.

The following release mechanisms that can disperse radioactive material into the atmosphere have been evaluated:

1. Reactor coolant releases via the ruptured tube into the affected steam generator, and eventually to the outside environment.

2. Normal primary to secondary leakage releases into the affected and intact steam generators, and eventually to the outside environment.

3. Main steam safety valve releases from the affected and intact steam generators to the outside environment.

15.10-178 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS

4. Turbine-driven auxiliary feed water pump venting of secondary steam from the affected and intact steam generators to the outside environment.

5. Atmospheric dump valve releases of secondary steam from the intact steam generator to the outside environment.

6. Leakage past one or more of the affected steam generator MSSVs and/or its ADV (subsequent to operator action to isolate the affected steam generator).

Conservatively, the total leakage is modeled as being equivalent to the flow capacity of a MSSV.

The principal assumptions and inputs for the dose analysis are presented below in Table 15.10.6.3.2-3.

15.10-179 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.2-1 Principal Assumptions and Inputs for SGTR Parameter Unit 2 Unit 3 Core Power 3478 MWth 3478 MWth Inlet Temperature 560°F 560°F RCS Pressure 2300 psia 2300 psia SG Pressure 900 psia 900 psia Core Flow, Total 376,200 gpm 376,200 gpm BOC Doppler Uncertainty Multiplier 0.86 0.86 Moderator Temperature Coefficient -3.7 x 10-4 'U/°F -3.7 x 10-4 'U/°F SCRAM Worth -6.0 % 'U -6.0 % 'U CPC (range - low pressure) Trip Set Point 1785 psia 1785 psia Loss of AC Power Coincident with Coincident with Reactor Trip Reactor Trip Steam Generator (S/G) U-Tube Break Size 45% Double 45% Double Ended Guillotine Ended Guillotine Safety Injection Actuation System - Set 1785 psia 1785 psia Point High Pressure Safety Injection - Response 15.0 seconds 15.0 seconds Time Main Feed Water (MFW) - Flow Rate 102% of Design 102% of Design Main Feed Water (MFW) - Enthalpy 425 Btu/lbm 425 Btu/lbm (pre-trip) (pre-trip)

Auxiliary Feed Water (AFW) - Response 57.7 secs. electric 57.7 secs. electric Time and steam driven and steam driven Auxiliary Feed Water (AFW) - Flow Rate 601 gpm at 1000 601 gpm at 1000 psia psia Auxiliary Feed Water (AFW) - Enthalpy 68 Btu/lbm 68 Btu/lbm Charging Flow Rate 135 gpm 135 gpm Letdown Flow Rate 0.0 gpm 0.0 gpm 15.10-180 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.2-1 (continued)

Principle Assumptions and Inputs for SGTR Parameter Unit 2 Unit 3 Main Steam Safety Valves (MSSV) - 1067 to 1120.4 1067 to 1120.4 Opening Set Points psia psia (9 valves at 7 psi increments. -3% Tolerance -3% Tolerance Includes set point tolerance)

MSSV Accumulation Set Point 0% 0%

MSSV Blow Down 15% (to fully 15% (to fully close) close)

Atmospheric Dump Valves (ADVs) Inoperative Inoperative Feed Water Control System (FWCS) Not Required to Not Required to Mitigate Event Mitigate Event Pressurizer Pressure Control System (PPCS) Not Required to Not Required to Mitigate Event Mitigate Event Steam Bypass Control System (SBCS) Inoperative Inoperative 15.10-181 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.2-2a Sequence of Events for SGTR, Unit 2 Time Chronological Event Set Point or Value (Seconds) 0.0 S/G Tube rupture occurs ----

1329.4 CPC Reactor Trip (low pressurizer pressure) 1785 psia setpoint reached, SIAS initiated 1330.3 Reactor Trip breakers open ----

Turbine Stop Valves close Loss of Normal AC 1333.1 MSSVs begin to open on both S/Gs 1067 psia 1337.9 Maximum S/G pressure on both generators 1112 psia 1356.1 Low S/G level signal generated, AFW initiated 115,610 lbm 1795.8 MSSVs close on both S/Gs 907 psia 1800.0 Damaged S/G isolated, ----

ADV on unaffected S/G opened to begin system cool down to Shut Down Cooling (SDC) 11880.0 Shut Down Cooling (SDC) initiated Temperature 350°F Total steam release 739,034 lbm 15.10-182 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.2-2b Sequence of Events for SGTR, Unit 3 Time Chronological Event Set Point or Value (Seconds) 0.0 S/G Tube rupture occurs ----

1329.4 CPC Reactor Trip (low pressurizer pressure) 1785 psia setpoint reached, SIAS initiated 1330.3 Reactor Trip breakers open ----

Turbine Stop Valves close Loss of Normal AC 1333.1 MSSVs begin to open on both S/Gs 1067 psia 1337.9 Maximum S/G pressure on both generators 1112 psia 1356.1 Low S/G level signal generated, AFW initiated 115,610 lbm 1795.8 MSSVs close on both S/Gs 907 psia 1800.0 Damaged S/G isolated, ----

ADV on unaffected S/G opened to begin system cool down to Shut Down Cooling (SDC) 11880.0 Shut Down Cooling (SDC) initiated Temperature 350°F Total steam release 739,034 lbm 15.10-183 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.2-3 Principal Assumptions and Inputs for Steam Generator Tube Rupture Dose Analysis Parameter Unit 2 Unit 3 AC Availability Loss of AC Loss of AC Power Power RCS Iodine Activity (Dose Equivalent I-131), Ci/gm 1.0 1.0 Increase in Iodine Release Rate from Fuel for Accident 500 500 Induced Iodine Spike RCS Pre-Existing Iodine Spike Iodine Activity (Dose 60 60 Equivalent I-131), Ci/gm RCS Non-Iodine Activity, Ci/gm 100/ 100/

Secondary Liquid Iodine Activity (Dose Equivalent 0.1 0.1 I-131), Ci/gm Steam Generator Iodine Partition Coefficient 0.01 0.01 Primary to Secondary Leak Rate into each SG, gpm 0.5 0.5 Integrated primary to secondary rupture flow, lbm 70,563 70,563 (1,800 seconds)

Additional primary to secondary rupture and normal 150,000 150,000 leakage flow available for release from 30 minutes to shut down cooling due to MSSV/ADV valve seat leakage, lbm Integrated MSSV flow, lbm (1,800 seconds)

LH - Unaffected 57,560 57,560 RH - Affected 57,664 57,664 Total MSSV Flow 115,224 115,224 AFW Flow (steam driven pump), lbm (1,800 seconds) 4,922 4,922 Steam Release (30 - 120 minutes), lbm 331,547 331,547 Total steam release (0 - 120 minutes), lbm 451,693 451,693 Total steam release to Shut Down Cooling, lbm 739,034 739,034 Additional affected steam generator steam release from 2,400,000 2,400,000 30 minutes to shut down cooling due to MSSV/ADV valve seat leakage, lbm Control Room Isolation Signal High Radiation High Radiation Control Room Isolation Time, min 3 3 Offsite Dose Evaluation Model Appendix 15B Appendix 15B and Appendix and Appendix 15.10B 15.10B Control Room Dose Evaluation Model Appendix 15B Appendix 15B and Appendix and Appendix 15.10B 15.10B 15.10-184 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Results The primary to secondary mass transfer and steam release data required to perform radiological calculations for the steam generator tube rupture event are presented in Table 15.10.6.3.2-3.

The RCS and secondary system pressures remain below the 110% of the design pressure limits, thus, assuring the integrity of these systems.

The results of the most recent analysis of the potential off site and control room personnel doses from a steam generator tube rupture with concurrent loss of normal AC power are presented in Table 15.10.6.3.2-4. These results are compared against the NRC approved acceptance criteria in section 15.6.3.2.

15.10-185 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.2-4 Results for Steam Generator Tube Rupture Analysis Results Parameter Acceptance Criteria Unit 2 Unit 3 Design Basis Case with No Iodine Spike 0-2 hr EAB Doses, Rem Thyroid 30 0.8 0.8 Beta Skin N/A 0.1 0.1 Whole Body 2.5 0.2 0.2 0-30 day LPZ Doses, Rem Thyroid 30 <0.1 <0.1 Beta Skin N/A <0.1 <0.1 Whole Body 2.5 <0.1 <0.1 0-30 day Control Room Doses, Rem Thyroid 30 1.8 1.8 Beta Skin 30 1.6 1.6 Whole Body 5 <0.1 <0.1 Design Basis Case with Pre-Existing Iodine Spike 0-2 hr EAB Doses, Rem Thyroid 300 8.2 8.2 Beta Skin N/A 0.1 0.1 Whole Body 25 0.2 0.2 0-30 day LPZ Doses, Rem Thyroid 300 0.2 0.2 Beta Skin N/A <0.1 <0.1 Whole Body 25 <0.1 <0.1 0-30 day Control Room Doses, Rem Thyroid 30 2.0 2.0 Beta Skin 30 1.6 1.6 Whole Body 5 <0.1 <0.1 Design Basis Case with Accident Induced Iodine Spike 0-2 hr EAB Doses, Rem Thyroid 30 4.1 4.1 Beta Skin N/A 0.1 0.1 Whole Body 2.5 0.2 0.2 0-30 day LPZ Doses, Rem Thyroid 30 0.1 0.1 Beta Skin N/A <0.1 <0.1 Whole Body 2.5 <0.1 <0.1 0-30 day Control Room Doses, Rem Thyroid 30 1.9 1.9 Beta Skin 30 1.6 1.6 Whole Body 5 <0.1 <0.1 15.10-186 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS 15.10.6.3.3 Loss of Coolant Accident There are two loss of coolant accident (LOCA) sequences which are evaluated. The first is the large break LOCA, the second is the small break LOCA. For each accident sequence there are two main topics of concern. The first topic is the mitigation of the increase in peak clad temperature and clad oxidation by the Emergency Core Cooling System (ECCS) within the NRC acceptance criteria. The second topic is the long term maintenance of acceptable low core temperatures (long term cooling). Since the realistic analysis (discussed in section 15.6.3.3.5.2) is not a part of the design basis, it is not included in this section.

Per Section 15.6.3.3.1 the large break LOCA analysis modeled the original steam generators with 2000 plugged tubes per steam generator. The results of the large break LOCA analysis are applicable to the replacement steam generators with up to 779 plugged per steam generator.

Additionally, per Section 15.6.3.3.3.2 the small break LOCA analysis modeled the original steam generators with 2805 plugged tubes per steam generator. The results of the small break LOCA analysis are applicable to the replacement steam generators with up to 779 plugged per steam generator.

Eight(8) AREVA Lead Fuel Assemblies (LFAs) are inserted into the Unit 2 Cycle 16 core. A fuel compatibility study was conducted to evaluate the effect of the addition of the AREVA LFAs on the ECCS performance for the Westinghouse fuel. For conservatism, a large break LOCA peak cladding temperature adder and maximum cladding oxidation adder have been applied to existing licensing basis analysis peak cladding temperature and maximum cladding oxidation values to represent the adverse effects of the AREVA LFAs. There is no effect on the small break LOCA PCT or on the post-LOCA long term cooling results for the Westinghouse fuel due to the addition of the AREVA LFAs.

Eight (8) Westinghouse Modified Standard Design (MSID) Lead Fuel Assemblies (LFAs) are inserted into the Unit 3 Cycle 16 core with non-limiting power peaking that is no more than 95%

of the peak power in the core. In support of this implementation the following ECCS performance evaluations have been performed: (1) a hot rod heatup analysis for the MSD LFAs to confirm that they remain non-limiting relative to the performance of the standard fuel assemblies for a large break LOCA, (2) a mixed core analysis to determine the peak cladding temperature delta and the maximum cladding oxidation delta impact for the MSD LFAs on the standard fuel ECCS performance for large break LOCA, (3) a small break LOCA peak cladding temperature evaluation for the standard Westinghouse fuel due to the addition of the MSD LFAs, (4) a post-LOCA long term cooling evaluation for the standard Westinghouse fuel due to the addition of the MSD LFAs with maximum creditable assembly deformation and blockage. The results of these ECCS performance evaluations confirm that the implementation of eight Westinghouse MSD LFAs remains bounded by the current design and licensing basis analyses with the addition of a small peak cladding temperature adder and a small maximum cladding oxidation adder on the limiting LBLOCA case for standard Westinghouse fuel.

15.10-187 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS 15.10.6.3.3.1 Large Break Loss of Coolant Accident Summary of Methods for Large Break LOCA An ECCS performance analysis of the large break LOCA limiting fault was performed to demonstrate compliance with the 10CFR50.46 acceptance criteria for emergency core cooling systems (ECCS) for light water nuclear power reactors. Design basis offsite and Control Room radiological doses were calculated.

The large break LOCA ECCS performance was performed with the NRC-accepted 1999 Evaluation Model (EM) version of the Westinghouse large break LOCA EM for Combustion Engineering Pressurized Water Reactors (PWRs). The principal assumptions and inputs for the large break LOCA analyses are presented in Table 15.10.6.3.3-1. The sequence of events is presented in Table 15.10.6.3.3-3.

Long term cooling after a large break LOCA must utilize simultaneous hot leg/cold leg injection to prevent precipitation of boric acid within the reactor vessel. The large break LOCA long term cooling evaluation was performed using the Table 15.10.6.3.3-2 input data and the June 1980 version of the Westinghouse large break LOCA long term cooling evaluation model. The sequence of events is presented in Table 15.10.6.3.3-3.

Details of the large break LOCA radiological consequence analysis are provided in section 15.6.3.3.1.5, and in appendices 15G and 15.10B. In accordance with the direction given in sections 15.0 and 15.0.7, additional information which completes the presentation of this event is provided in this section.

15.10-188 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.3-1 Principal Assumptions and Inputs for Large Break LOCA Parameter Unit 2 Cycle 16 Unit 3 Cycle 16 Limiting Break Size 0.6 DEG/PD 0.6 DEG/PD Pressurizer Pressure Control System N/A N/A Pressurizer Level Control System N/A N/A Steam Bypass Control System N/A N/A Core Power, MWt 3458 3458 Initial Peak Linear Heat Generation Rate, kW/ft 12.8 12.8 Cold Leg Temperature, °F 530 530 Hot Leg Temperature, °F 592.7 592.7 Number of Plugged Steam Generator Tubes (per 779 779 SG)

RCS Flow Rate at 530°F, 106 lbm/hr 144.9 144.9 Core Flow Rate at 530°F, 106 lbm/hr 140.6 140.6 Single Failure per section per section 6.3.3.2.1 6.3.3.2.1 Reactor Trip Signal N/A N/A ECCS Pump/Flow Requirements per section per section 6.3.3.2.1 6.3.3.2.1 15.10-189 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.3-2 Principal Assumptions and Inputs for Large Break LOCA Long Term Cooling Parameter Unit 2 Unit 3 Break Size 0.012 ft2 0.012 ft2 Reactor Power 3458 MWt 3458 MWt Pressurizer Pressure Control System N/A N/A Pressurizer Level Control System N/A N/A Steam Bypass Control System N/A N/A Containment Pressure 14.7 psia 14.7 psia Time at which approximately half of HPSI 2-3 hr 2-3 hr flow is realigned to hot legs (remainder stays aligned to cold legs)

Time by which the decision is made to use 6 hr 6 hr large break or small break LTC plan Decision pressure (of RCS) for using large 260 psia 260 psia break or small break cooldown methodology Single Failure One Diesel One Diesel Generator Generator Additional Restrictions in Addition to Single Only one ADV Only one ADV Failure and one AFW and one AFW Pump are Pump are available available 15.10-190 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.3-3a Sequence of Events for Large Break LOCA, Unit 2 Cycle 16 Time (sec) Event Setpoint or Value 0.0 LOCA occurs -------

0.0 Control Room HVAC isolates on SIAS -------

1800 to Operators initiate core cooldown -------

3600 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> Operators realign approximately 50% of HPSI flow to -------

hot legs 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Decision is made as to cooldown methodology to be -------

used (large or small break) 30 days End of Offsite and Control Room dose evaluation -------

intervals Table 15.10.6.3.3-3b Sequence of Events for Large Break LOCA, Unit 3 Cycle 16 Time (sec) Event Setpoint or Value 0.0 LOCA occurs -------

0.0 Control Room HVAC isolates on SIAS -------

1800 to Operators initiate core cooldown -------

3600 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> Operators realign approximately 50% of HPSI flow to -------

hot legs 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Decision is made as to cooldown methodology to be -------

used (large or small break) 30 days End of Offsite and Control Room dose evaluation -------

intervals 15.10-191 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table of Results for Large Break LOCA Table 15.10.6.3.3-4 presents the results of the most recent analyses of the large break LOCA limiting fault. The ECCS performance parameters are compared against the 10CFR50.46 criteria presented in Section 15.6.3.3.3.1.C.

Table 15.10.6.3.3-4 Non-Radiological Results for Large Break LOCA Analysis Results Acceptance Parameter Unit 2 Unit 3 Criteria Cycle 16 Cycle 16 Maximum Hydrogen Generation 1.0% <0.99% <0.99%

(Core-Wide Cladding Oxidation) 15.6.3.3.3.1.C Maximum Cladding Oxidation 17% 15.31% 15.29%

15.6.3.3.3.1.C Peak Cladding Temperature 2200°F 2174°F 2173°F 15.6.3.3.3.1.C Coolable Geometry Maintained Yes Yes Yes 15.6.3.3.3.1.C Long Term Cooling Maintained Yes Yes Yes 15.6.3.3.3.1.C Table 15.10.6.3.3-5 compares the LOCA dose consequences against the NRC approved acceptance criteria described in section 15.6.3.3.5.

The EAB and LPZ offsite doses for the LOCA event do not exceed the dose acceptance criterion described in section 15.6.3.3.5.

The Control Room dose for the LOCA does not exceed the dose acceptance criterion described in section 15.6.3.3.5.

15.10-192 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS TABLE 15.10.6.3.3-5 LOCA DOSE CONSEQUENCES LOCA Acceptance Dose Receptor Dose Criterion (REM TEDE) (REM TEDE)

Control Room (30-day accident duration) 2.8 5 EAB (Maximum 2-hour dose) 5.2 25 LPZ (30-day accident duration) 1.9 25 15.10-193 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS 15.10.6.3.3.2 Small Break Loss of Coolant Accident Summary of Methods for Small Break LOCA An ECCS performance analysis of the small break LOCA limiting fault was performed to demonstrate compliance with the 10CFR50.46 acceptance criteria for emergency core cooling systems (ECCS) for light water nuclear power reactors. Various break sizes between 0.03 ft2 and 0.05 ft2 were evaluated. Radiological doses were not specifically evaluated, since the radiological consequences are bounded by the large break LOCA.

Using the Table 15.10.6.3.3-6 input data, the NSSS response to this transient was determined using the NRC approved S2M version of the Westinghouse small break LOCA ECCS performance evaluation model. The sequence of events is presented in Table 15.10.6.3.3-8.

Table 15.10.6.3.3-6 Principal Assumptions and Inputs for Small Break LOCA Parameter Unit 2 Unit 3 Break Sizes Evaluated, ft2 0.03 to 0.05 0.03 to 0.05 Pressurizer Pressure Control System Inoperative Inoperative Pressurizer Level Control System Inoperative Inoperative Steam Bypass Control System Inoperative Inoperative Core Power, MWt 3458 3458 Initial Peak Linear Heat Generation Rate, 13.5 13.5 kW/ft Number of Plugged Steam Generator Tubes 779 779 (per SG)

RCS Flow Rate, 106 lbm/hr 139.4 139.4 Core Flow Rate, 106 lbm/hr 135.2 135.2 Moderator Temperature Coefficient, 10- 0.0 0.0 4

'U/°F Single Failure per section per section 6.3.3.3.1 6.3.3.3.1 Reactor Trip Signal Low Pressurizer Low Pressurizer Pressure Pressure ECCS Pump/Flow Requirements per section per section 6.3.3.3.1 6.3.3.3.1 Safety Injection Tank Minimum Pressure, 595 595 psia Radiological Consequences Not Evaluated Not Evaluated 15.10-194 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Long term cooling after a small break LOCA must utilize the steam generators to cool the RCS to the point where shutdown cooling can be placed in service. The small break LOCA long term cooling evaluation was performed using the Table 15.10.6.3.3-7 input data and the June 1980 version of the Westinghouse small break LOCA long term cooling evaluation model. The sequence of events is presented in Table 15.10.6.3.3-8.

Table 15.10.6.3.3-7 Principal Assumptions and Inputs for Small Break LOCA Long Term Cooling Parameter Unit 2 Unit 3 Break Size 0.017 ft2 0.017 ft2 Reactor Power 3458 MWt 3458 MWt Pressurizer Pressure Control System N/A N/A Pressurizer Level Control System N/A N/A Steam Bypass Control System Used if available Used if available Number of Tubes Plugged, per Steam 779 779 Generator Time at which approximately half of HPSI 2-3 hr 2-3 hr flow is re-aligned to hot legs (remaining half stays aligned to cold legs)

Time when the decision is made to use large 6 hr 6 hr break or small break LTC plan Decision pressure (of RCS) for using large 260 psia 260 psia break or small break cooldown methodology Single Failure One Diesel One Diesel Generator Generator ECCS Pump/Flow Requirements per section per section 6.3.3.4.2 6.3.3.4.2 Additional Restrictions in Addition to Single Only one ADV Only one ADV Failure and one AFW and one AFW Pump are Pump are available available 15.10-195 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table 15.10.6.3.3-8a Sequence of Events for Small Break LOCA, Unit 2 Time (sec) Event Time for Break Size (seconds) 0.03 ft2 0.04 ft2 0.05 ft2 SBLOCA occurs 0 0 0 SIAS Generated 231 159 126 MSSVs Open 243 168 135 MSSVs Close (broken loop) 3730 2750 2420 MSSVs Close (intact loop) 3710 1120 850 Initiate core cooldown 1800 to 3600 Operators realign 50% of HPSI 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> flow to hot legs Decision made as to cooldown 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> methodology to be used (large or small break)

Table 15.10.6.3.3-8b Sequence of Events for Small Break LOCA, Unit 3 Event Time for Break Size (seconds)

Time (sec) 0.03 ft2 0.04 ft2 0.05 ft2 Deleted SBLOCA occurs 0 0 0 Deleted SIAS Generated 231 159 126 Deleted 243 168 135 Deleted MSSVs Open MSSVs Close (broken loop) 3730 2750 2420 Deleted MSSVs Close (intact loop) 3710 1120 850 Deleted Initiate core cooldown 1800 to 3600 Operators realign 50% of HPSI 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> flow to hot legs Decision made as to cooldown 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> methodology to be used (large or small break) 15.10-196 Rev: 44

San Onofre 2&3 FSAR Updated TRANSIENT ANALYSIS Table of Results for Small Break LOCA Table 15.10.6.3.3-9 presents the results of the most recent analysis of the small break LOCA limiting fault. The ECCS performance parameters are compared against the 10CFR50.46 criteria presented in Section 15.6.3.3.3.1.C. The offsite radiological doses are compared against the NRC approved acceptance criteria presented in Section 15.6.3.3.5.1.E. The Control Room radiological doses are compared against the NRC approved acceptance criteria presented in Section 15.6.3.3.5.1.F.

Table 15.10.6.3.3-9 Results for Small Break LOCA Acceptance Analysis Results Parameter Criteria Unit 2 Unit 3 Maximum Hydrogen Generation 1.0% < 0.74% < 0.74%

(Core Wide Cladding Oxidation)

Maximum Cladding Oxidation 17% 14.11% 14.11%

Peak Cladding Temperature 2200°F 2077°F 2077°F Coolable Geometry Maintained Yes Yes Yes Long Term Cooling Maintained Yes Yes Yes Offsite Radiological Doses 10CFR100 Bounded by Bounded by large break large break LOCA LOCA Control Room Radiological 10CFR50 Bounded by Bounded by Doses Appendix A large break large break GDC 19 LOCA LOCA Conclusion As described in section 15.6.3.3 the ECCS meets the 10CFR50.46 acceptance criteria, and the offsite radiological doses do not exceed 10 CFR Part 100 exposure guidelines. The Control Room radiological doses do not exceed the 10 CFR 50 Appendix A General Design Criterion 19 exposure guidelines.

15.10.6.3.4 Inadvertent Opening of a Pressurizer Safety Valve Introduction The Inadvertent Opening of a Pressurizer Safety Valve (IOPSV) event is classified as a limiting fault. UFSAR section 15.6.3.4.5 states that the dose consequences of the IOPSV are less severe than the Inadvertent Opening of a Steam Generator Atmospheric Dump Valve with a concurrent single failure of a Loss of Offsite Power (IOSGADV w/SF).

15.10-197 Rev: 44

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS APPENDIX 15 B DOSE MODELS USED TO EVALUATE THE CONSEQUENCES OF ACCIDENTS ANALYZED WITH THE TID-14844 METHODOLOGY 15B.1 INTRODUCTION San Onofre Units 2 and 3 are licensed for full scope implementation of the Alternative Source Term (AST) methodology for radiological consequence analyses. All future radiological analyses performed to show compliance with regulatory requirements shall address all characteristics of the AST and the Total Effective Dose Equivalent (TEDE) criteria of 10CFR50.67. Appendix 15G identifies the models used to calculate offsite and control room radiological doses due to postulated accidents evaluated in accordance with the AST dose analysis methodology of Regulatory Guide 1.183.

This appendix identifies the pre-AST models used to calculate offsite and control room radiological doses that would result from releases of radioactivity due to various postulated accidents. The pre-AST models are in accordance with the Technical Information Document (TID)-14844 dose analysis methodology (Reference 9).

Appendix 15.10B presents clarifications and additions to the dose models presented in this appendix. The appendix 15.10B dose model clarifications and additions have been implemented pursuant to the guidance of the 10CFR50.59 rule.

The postulated accidents that have been analyzed using the TID-14844 methodology are:

A. Steam generator tube rupture (including an evaluation of control room doses)

B. Primary sample or instrument line break C. Waste gas system failure D. Radioactive liquid waste system leak or failure 15B.2 ASSUMPTIONS The following assumptions are basic to both the model for the whole body dose due to immersion in a cloud of radioactivity and the model for the thyroid dose due to inhalation of radioactivity:

A. All radioactive releases are treated as ground level releases regardless of the point of discharge.

15B-1 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS B. The dose receptor is a standard man, as defined by the International Commission on Radiological Protection.(1)

C. No credit is taken for cloud depletion by ground deposition and radioactive decay during transport to the exclusion area boundary or the outer boundary of the low-population zone.

D. Isotopic data, including decay constants and decay energies presented in tables 15B-1, 15B-2 and 15B-6 are taken from references 2 through 9.

15B.

2.1 REFERENCES

1. "Report of ICRP Committee II, Permissible Dose for Internal Radiation (1959)," Health Physics, 3, p. 30, 146-153, 1960.

2. Martin, M. J. and Blichert-Toft, P. H., Radioactive Atoms, Auger-Electron, -, -, -, and X-Ray Data, Nuclear Data Tables A8, 1, 1970.

3. Martin, M. J., "Radioactive Atoms - Supplement 1," ORNL-4923, August 1973.

4. Bowman, W. W. and MacMurdo, K. W., "Radioactive Decay Gammas, Ordered by Energy and Nuclide," Atomic Data and Nuclear Data Tables 13, Nos. 2-9, 1974.

5. Meek, M. E. and Gilbert, R. S., "Summary of Gamma and Beta Energy and Intensity Data,"

NEDO-12037, January 1970.

6. Lederer, C. M., Hollander, J. M., and Perlman, I., Table of the Isotopes, 6th edition, March 1968.

7. Regulatory Guide 1.109, Rev. 1, October 1977, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I.

8. TID-14844, Calculation of Distance Factors for Power and Test Reactor Sites, AEC, 1962.

9. ICRP Publication 30, Supplement to Part 1, Limits for Intakes of Radionuclides by Workers, International Commission on Radiological Protection, adopted July 1978.

15B-2 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS 15B.3 WHOLE BODY GAMMA AND BETA SKIN DOSE The whole body dose delivered to an offsite receptor is obtained by considering the dose receptor to be immersed in a radioactive cloud that is infinite in all directions above the ground plane; i.e., an infinite hemispherical cloud. The concentration of radioactive material within this cloud is uniform and equal to the maximum centerline ground level concentration that would exist in the cloud at the appropriate distance from the point of release.

The gamma dose due to gamma radiation, equation (1), and the beta dose due to beta radiation, equation (2), are as follows:

Dwb = /Q * (Qi

• DCFwbi) (1) i Ds = /Q * (Qi

• DCFsi) (2) i where:

Dwb = whole body dose from gamma radiation (rem)

Ds = skin dose from beta radiation (rem)

/Q = Site atmospheric dispersion factor during time period (s/m3)

Qi = Total activity of isotope i released during time period (Ci)

DCFwbi = Whole body dose conversion factor for isotope i (rem-m3/Ci-Sec)

DCFsi = Beta skin dose conversion factor for isotope i (rem-m3/Ci-Sec)

The atmospheric dispersion factors used in the analysis of the environmental consequences of accidents are given in chapter 2 of this report. The offsite receptor whole-body gamma and beta-skin dose conversion factors used are calculated from the average gamma and beta energies given in Table 15B-1, using the following equations from Regulatory Guide 1.4:

15B-3 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Dwb = 0.25 * /Q * (Qi

• i) (4) i Ds = 0.23 * /Q * (Q1

• i) (5) i where:

Dwb = whole body dose from gamma radiation (rem)

Ds = skin dose from beta radiation (rem)

/Q = Site atmospheric dispersion factor during time period (s/m3)

Qi = total activity of isotope i released during time period (Ci)

Ei = average gamma or beta decay energy from isotope i (MeV/disintegration)

The isotopic data are given in table 15B-1. The atmospheric dispersion factors used in the analysis of the environmental consequences of accidents are given in chapter 2 of this report.

15B.4 THYROID INHALATION DOSE The thyroid dose for a given time period is obtained from the following expression:(1)

D = /Q

• B * (Qi

• DCFi) (3) i where:

D = thyroid inhalation dose (rem)

/Q = site atmospheric dispersion factor during the time period (s/m3)

B = breathing rate during the time period (m3/s)

Qi = total activity of isotope i released during time period (Ci)

DCFi = dose conversion factor for isotope i (rem/Ci inhaled)

The atmospheric dispersion factors used in the analysis of the environmental consequences of accidents are given in chapter 2 of this report.

Dose conversion factors for radioactive iodines and breathing rates required for computing thyroid inhalation dose are tabulated in tables 15B-6 and 15B-3, respectively. Some previous analyses used the thyroid dose conversion factors listed in Table 15B-2.

15B-4 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS 15B.

4.1 REFERENCES

1. DiNunno, J. J., et al., Calculation of Distance Factors for Power and Test Reactor Sites, TID 14844, March 1962.

15B-5 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Table 15B-1 ISOTOPIC PARAMETERS Average MeV/Disintegration MeV/Disintegration Isotope Half-Life(a) (gamma) (beta)

I-131 8.06 D 0.381 0.194 I-132 2.28 H 2.333 0.519 I-133 21 H 0.608 0.403 I-134 52 M 2.529 0.558 I-135 6.7 H 1.635 0.475 Kr-83m 1.86 H 0.002481 0.03708 Kr-85m 4.48 H 0.159 0.253 Kr-85 10.73 Y 0.00221 0.251 Kr-87 76.31 M 0.793 1.324 Kr-88 2.80 H 1.950 0.375 Xe-131m 11.9 D 0.020 0.143 Xe-133m 2.25 D 0.0416 0.190 Xe-133 5.29 D 0.0454 0.135 Xe-135m 15.65 M 0.432 0.095 Xe-135 9.15 H 0.247 0.316 Xe-138 14.17 M 1.183 0.606 H-3 12.3 Y None 0.006 (a)

D [days], H [hours], M [minutes], Y [years]

Table 15B-2 IODINE DOSE CONVERSION FACTORS USED IN EARLIER ANALYSES(a)

Isotope Inhalation Thyroid DCF(b) Inhalation Thyroid DCF(c)

(rem/Ci) (rem/Ci)

I-131 1.48 x 106 1.49 x 106 I-132 5.35 x 104 1.43 x 104 I-133 4.00 x 105 2.69 x 105 I-134 2.50 x 104 3.73 x 103 I-135 1.24 x 105 5.60 x 104 (a)

Earlier analyses refer to analyses completed prior to January 1, 1999. See Table 15B-6 for values used in current dose analyses.

(b)

From Table III of TID-14844, AEC, 1962.

(c)

From Table E-7 of Regulatory Guide 1.109, Revision 1, October 1977.

15B-6 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Table 15B-3 OFFSITE BREATHING RATES Time After Accident m3/s 0 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 3.47 x 10-4 8 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 1.75 x 10-4 1 to 30 days 2.32 x 10-4 15B.5 CONTROL ROOM DOSE During the course of an accident, control room personnel may receive doses from the following sources:

A. Direct whole body gamma dose from the radioactivity present in the containment building.

B. Direct whole body gamma dose from the radioactive cloud surrounding the control room.

C. Whole body gamma, thyroid inhalation, and beta skin doses from the airborne radioactivity present in the control room.

D. Direct whole body gamma dose from the radioactivity present in piping.

E. Direct whole body gamma dose from emergency HVAC intake charcoal filters.

In calculating the exposure to control room personnel, occupancy factors were obtained from reference 1 as follows:

• 0-24 hours: occupancy factor = 1

• 1-4 days: occupancy factor = 0.6

• 4-30 days: occupancy factor = 0.4 These occupancy factors are embedded in the Table 15B-4 control room atmospheric dispersion factors.

The dose model for each of the radiation sources is discussed below:

A. Direct whole body gamma dose from the radioactivity present in the containment building (direct containment dose).

Time integrated (0 to 30 days) isotopic concentrations in the containment are calculated.

For conservatism, no credit is taken for reduction of the containment activity by means 15B-7 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS other than radioactive decay. The containment is modeled by an equivalent volume cylindrical source having a diameter of 150 feet and height of 130 feet. The radioactivity present in the containment is assumed to be uniformly distributed in the cylindrical source.

Shielding is assumed to be provided by a 3-foot 9-inch concrete containment walls, 180 feet of air separating the containment building from the control building, and 2-foot thick control room walls. No credit is taken for attenuation between the containment building and the control building.

No credit is taken for any shielding that could be provided by the penetration building.

B. Direct whole body gamma dose from the radioactive cloud surrounding the control room (outside cloud dose).

Leakage from the containment building, or any building, will result in the formation of a radioactive cloud. For conservatism it is assumed that this cloud surrounds the control room. Gamma radiation from this cloud can penetrate the control room roof and walls resulting in a whole body gamma dose to control room personnel. The radius of the cloud is computed using a mass balance of the radioactivity released due to leakage and the volume of the cloud; therefore, the radioactive cloud is time variant and expands for the duration of the accident.

Radioactivity concentrations (Ci/m3) in the radioactive cloud surrounding the control room is the product of the building leak rate (Ci/s) and the control room atmospheric dispersion factor, /Q (s/m3). Calculations used to compute atmospheric dispersion factors using Murphy-Campe methodology are presented in subsection 2.3.4. A tabulation of control room /Qs is presented in table 15B-4.

Meteorological parameters are given in section 2.3, while the calculated /Q values, for those accidents for which control room dose calculations were performed, are presented in table 15B-4.

The calculational model for the control room is an equivalent volume hemisphere of radius 52 feet. Credit is taken for 2 feet of concrete shielding provided by the control room walls, and 3 feet of concrete shielding provided by the ceiling.

C. Dose from the airborne radioactivity present in the control room (occupancy dose).

Airborne radioactivity will be drawn into the control room due to the intake of outside air required to maintain a positive pressure in the control room. This contributes to the whole body gamma, thyroid inhalation, and beta skin doses. The major parameters of the control room ventilation system are presented in table 15B-5.

15B-8 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Table 15B-4 ATMOSPHERIC DISPERSION FACTORS FOR THE SAN ONOFRE SITE

/Q (s/m3)

Control Room(a) EAB LPZ Time Period 5% 50% 5% 50% 5% 50%

Hourly 2.72 x 10-4 3.6 x 10-6 0-8 hours 3.1 x 10-3 7.9 x 10-4 7.72 x 10-6 9.24 x 10-7 8-24 hours 1.8 x 10-3 4.6 x 10-4 4.74 x 10-6 6.03 x 10-7 1-4 days 5.9 x 10-4 1.5 x 10-4 3.67 x 10-6 3.65 x 10-7 4-30 days 9.6 x 10-5 2.5 x 10-5 2.67 x 10-6 3.28 x 10-7 (a)

The atmospheric dispersion factors calculated using Murphy-Campe methodology include a Control Room Occupancy (CRO) factor of:

0-8 hours 1 8-24 hours 1 1-4 days 0.6 4-30 days 0.4 15B-9 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Table 15B-5 CONTROL ROOM EMERGENCY VENTILATION SYSTEM PARAMETERS(a)

Parameter Assumption Number of emergency ventilation system 2 (c) operating Intake rate, standard ft3/min (8+ hours) 2,200 (0-8 hours) 4,400 Intake cleanup filter efficiency (b)

Iodine, elemental, %

Iodine, organic, %

Iodine, particulate, %

Others, %

Recirculation rate, standard ft3/min (8+ hours) 31,900 (0-8 hours) 63,800 Recirculation cleanup filter efficiency Iodine, elemental, % 95 Iodine, organic, % 95 Iodine, particulate, % 99 Others, % 99 Unfiltered inleakage, standard ft3/min 10 Exhaust flow, standard ft3/min sum of inflow and inleakage Control room volume, standard ft3 244,398 (a)

There are two completely redundant emergency control room ventilation systems.

For a more detailed description of this system, refer to subsection 9.4.2.

The technical support center is located within the control room emergency HVAC envelope.

The doses to technical support center personnel will be lower than that for the control room due to the concrete floor attenuating the radiation from the HVAC charcoal filter.

(b)

No credit is taken for this filter removing radioactivity when calculating control room infiltration doses. However, a filter efficiency of 100% is assumed when evaluating the filter as a direct whole body gamma source. Note that the intake flow passes through the recirculation filter prior to entering the control room.

(c)

Control room emergency intake air filtration unit will not operate if its associated recirculating system is off. Includes operator action to deactivate one train of emergency intake and recirculation units within eight hours if both trains are operating.

15B-10 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Meteorological parameters are given in section 2.3, while the control room atmospheric dispersion factors calculated using Murphy-Campe methodology, for those accidents for which control room dose calculations were performed, are presented in table 15B-4.

The whole body gamma dose is computed using a finite cloud model.

The gamma dose to the control room personnel is calculated assuming a finite cloud model.

The gamma dose due to gamma radiation in the control room for a given time period is:

(CRVOL )0.338 (IQi )(3600)(CRO)

Dwb =

1173 i

DCFwbi (CRVOL)(0.02832)

(1) where:

Dwb = whole body gamma dose to control room personnel from gamma radiation, (rem)

CRO = the control room occupancy factor 1 3600 = conversion factor, s/h 0.02832 = conversion factor, m3/ft3 CRVOL = control room volume, ft3 IQi = total integrated activity for nuclide i in control room for the time period, (Ci-hr)

DCFwbi = the semi-infinite cloud whole body gamma dose conversion factor for nuclide i, (rem-m3/Ci-s). (See table 15B-6).

The expression (CRVOL)0.338/1173 is a geometrical correction factor to ratio a finite cloud to infinite cloud (reference 1).

The beta skin dose to control room personnel is calculated assuming a tissue depth of 7 mg/cm2.

The beta skin dose to control room personnel for a given time period is:

CRO D s = D si IQi 3600 (CRVOL)(0.02832) i 15B-11 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS where:

Dsi = the beta skin dose conversion factor for nuclide i, (rem-m3/Ci-sec). (See table 15B-6) and all other parameters are as previously defined.

An inhalation thyroid dose results from the radioactive iodine present in the control room.

The inhalation thyroid dose is given by the following expression:

(B)(CRO)(3600)

Dthy = DCFthy A3 (3)

(CRVOL)(0.02832) i where:

Dthy = inhalation thyroid dose (rem)

B = control room operator breathing rate for duration of accident (3.47 x 10-4 m3/sec)

DCFthy = thyroid dose conversion factor for nuclide i, (rem/Ci inhaled) (see table 15B-6)

A3 = integrated activity in control room (Ci-hr)

NOTE: The CRO factor is already included in the /Q's listed in Table 15B-4, which are used to calculate the integrated activity (A3).

All other parameters are as previously defined.

D. Direct whole body gamma dose from radioactivity present in piping.

Direct radiation from piping used in the post-accident mode of operation will contribute to the control room whole body gamma dose.

This piping is modeled as a finite length shielded cylinder. Credit is taken for concrete shield floors and walls of the penetration, control and radwaste buildings, as well as the control room shield door.

15B-12 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Table 15B-6 WHOLE BODY GAMMA, BETA SKIN AND INHALATION THYROID DOSE CONVERSION FACTORS Whole Body Inhalation (a)

Beta Skin DCF Gamma DCF(a) Thyroid DCF(d)

Radionuclide (rem - m3/ci - s) (rem-m3/Ci-s) (rem/Ci)

I-131 3.170E-02 8.720E-02 1.07E+06 I-132 1.320E-01 5.130E-01 6.29E+03 I-133 7.350E-02 1.550E-01 1.81E+05 I-134 9.230E-02 5.320E-01 1.07E+03 I-135 1.290E-01 4.210E-01 3.15E+04 Kr-83m 0.000E+00 2.396E-06 Kr-85m 4.626E-02 3.708E-02 Kr-85 4.246E-02 5.102E-04 Kr-87 3.083E-01 1.876E-01 Kr-88 7.510E-02 4.658E-01 Kr-89 3.200E-01 5.260E-01 Xe-131m 1.508E-02 2.899E-03 Xe-133m 3.150E-02 7.954E-03 Xe-133 9.697E-03 9.316E-03 Xe-135m 2.253E-02 9.887E-02 Xe-135 5.894E-02 5.736E-02 Xe-137 3.866E-01 4.500E-02 Xe-138 1.309E-01 2.798E-01 H-3 0.000E+00 0.000E+00 0.000E+00(b)

Non-gaseous 0.000E+00(c) 0.000E+00(c) 0.000E+00(b)(c) isotopes (a)

From Regulatory Guide 1.109, Revision 1, October 1977.

(b)

Per 10CFR § 100.11(a)(1) the thyroid dose is based only on iodine exposure.

(c)

Non-gaseous isotopes are assumed to plate-out or deposit prior to reaching the offsite or control room dose receptors.

(d)

From ICRP-30, Supplement to Part 1, pages 192-212, Tables titled, Committed Dose Equivalent in Target Organs or Tissues per Intake of Unit Activity.

15B-13 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS E. Direct whole body gamma dose from radioiodine buildup on control building emergency HVAC filter.

The quantity of iodine entering the filter, following a postulated accident, is determined in a manner identical to that described in item C. The dose in the control room is determined by numerical integration of a distributed source model. Filter self-attenuation and dose buildup is modelled. Attenuation by interposed equipment is conservatively neglected. For the direct dose calculation, the filter efficiency is conservatively assumed to be 100%.

15B.

5.1 REFERENCES

1. Murphy, K. G. and Campe, K. M. , Dr., "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19," Proceedings of the 13th AEC Air Cleaning Conference held August 12-15, 1974, CONF. 740807, Vol. 1, pp. 401-430.

15B-14 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS 15B.6 ACTIVITY RELEASE MODELS 15B.6.1 ACCIDENT RELEASE PATHWAYS The release pathways for the major accidents are given in table 15B-7 and shown schematically in figure 15B-1. The letters (A-D, B-C-D, etc.) refer to the labels used in figure 15B-1. The accident and their pathways are as follows.

15B.6.1.1 Direct Filtered No accident release pathways involve direct filtered leakage. The release pathway is B-C-D, as shown on figure 15B-1. The applicable equation for calculating activity release for offsite doses is equation (5). Control room internal doses are based on activity release calculated using equation (6).

15B.6.1.2 Direct Unfiltered The accident release pathways for the accidents listed in paragraph 15.B.1, less those accidents described in paragraph 15B.6.1.1, involve direct unfiltered leakage. The release pathway is A-D, as shown on figure 15B-1. The applicable equation for calculating activity release for offsite doses is equation (5). Control room internal doses are based on activity release calculated using equation (6).

15B.6.2 SINGLE REGION RELEASE MODEL A single region release model was used for all accident activity offsite release calculations.

The single region release model is based on two release paths to the environment; (1) direct unfiltered, and/or (2) direct filtered.

It is assumed that any activity released to a region instantaneously diffuses to uniformly occupy the region volume.

The following equations are used to calculate the integrated activity released from postulated accidents.

15B-15 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS Table 15B-7 ACCIDENT LEAKAGE PATHWAYS (Refer to figure 15B-1)

Accident Pathway Legend A. Steam generator tube rupture Steam dump and Safety Valves Atm Control Room A-D-E B. Primary sample or instrument line break

1. Primary release Reactor coolant system Atm(a) A-D C. Waste gas system failure Auxiliary building (radwaste area) Atm(a) A-D D. Radioactive liquid waste system Auxiliary building (radwaste area) Atm(a) A-D leak or failure (a)

End of release path for offsite doses 15B-16 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS A1 (t) = A1 (O) e 1

- t (1) where:

A1(O) = initial source activity at time t = 0, Ci A1(t) = source activity at time t, Ci 1 = total removal constant from primary holdup system 1 = d + 1l + r where:

d = decay removal constant 1l = primary holdup leak or release rate r = internal removal constant (i.e., sprays, plateout, etc.)

From this we get the direct release rate to the atmosphere from the primary holdup system.

Ru(t) = a 1l A1(t) (2) where:

a = direct unfiltered fraction of leak Ru(t) = unfiltered release rate (Ci/sec) and Rf(t) = b 1l F1 A1(t) (3) where:

b = direct filtered fraction of leak F1 = filter nonremoval efficiency Rf(t) = filtered release rate (Ci/sec) 15B-17 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS The total release rate is then the sum of the two release pathways.

Rt(t) = Ru(t) + Rf(t) (4) or Rt(t) = a 1l A1(t) = b 1l F1A1(t) (4a)

The total integrated activity release is then the integral of the above equation.

IAR(t) = R u (t) + R f (t)

This yields (a 1l + b 1l F1) A1 (O)

IAR(t) = (1 - e )

-1 t (5) 1 where:

IAR(t) = total integrated activity release at time t, (Ci) 15B-18 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS 15B.7 INTEGRATED ACTIVITY IN CONTROL ROOM The integrated activity in the control room during each time interval is found by multiplying the release by the appropriate /Q to give a concentration of the control room intake. This activity is brought into the control room through the filtered intake valves and by unfiltered inleakage and is subjected to the control room ventilation system of recirculation through charcoal filters and exhaust to the atmosphere.

INTAKE

>FILTER CONTROL FILTER RELEASES ROOM RECIRCULATION UNFILTERED LEAKAGE EXHAUST (a)

Credit is not taken for the intake filter.

15B-19 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS 15B.7.1 ACTIVITY RELEASE MODEL FOR CONTROL ROOM 15B.7.1.1 General Equation The activity released from a postulated accident is calculated by using the following matrix equation for each isotope and each specie of iodine:

dA

+ C A = S; initial condition A( t o) = Ao (6) dt A1 = L A I where:

A(t) = (ai(t))

ai = the activity in the ith node, (Ci)

C = (Cij) matrix Cij = the transfer rate from the ith node to the jth node, (s-1)

S = (Si) vector Si = the production rate in the ith node (Ci/sec)

A1 = the activity released to the environment over the time period (Ci)

L = (l i) matrix li = the leak rate from the ith node to environment (Ci/sec) t1 A I = A(t) dt (Ci/sec) to Each node represents a volume where activity can be accumulated. The environment and the control room are each represented by a node. To ensure that the system of differential equations has constant coefficients, the time scale is broken up into time intervals over which all parameters are constant. Thus, all coefficients and sources are assumed to be representable by step functions.

15B-20 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS The matrix equation is solved using matrix techniques. The particular solution is obtained by Gaussian elimination. The homogenous solution is obtained by solving for the eigenvectors and the eigenvalues of the coefficient matrix C. They are determined by using QR transformation techniques.

The following section describes how the coefficient matrix and the source vector are calculated for the different accident calculations.

15B.7.1.2 The Model for Containment Leakage The model for containment leakage is shown in figure 15B-1. The system of differential equations for estimating the released activity is as follows:

(7a) dA1

- L21 A 2 = 0 dt dA 2 (7b)

+ (d + s + L21) A 2 = 0 dt dA 3 X (L u + [1 f L ] L f ) L 21 A 2 (7c) dt Q

[ ]

+ ( L f + Lu / [Vc (0.02832)] + f R Rc + d ) A3 = 0 where:

A1(t) = activity in the environment, (Ci)

A2(t) = activity in the containment, (Ci)

A3(t) = activity in the control room, (Ci) d = radioactive decay constant, (s-1)

L21 = T 21 , (s-1)

(100%)(24)(3600)

T21 = leak rate from the containment to the environment (%/day) s = the spray removal constant, (s-1) 15B-21 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS (0.02832)

Lu = Tu , (m3 /s) 60 Tu = unfiltered inleakage into the control room, (ft3/min)

(0.02832)

Lf = Tf , (m3 /sec) 60 Tf = filtered air intake rate into the control room, (ft3/min) fL = filter efficiency of the filters on the intake units

/Q = atmospheric dispersion factor for the control room, (s/m3)

(NOTE: The /Q's calculated using Murphy-Campe methodology for the control room in Table 15B-4 contain a Control Room Occupancy factor.)

Rc = Tr , (s-1)

(Vc)(60)

Tr = filtered recirculation rate in the control room, (ft3/min)

Vc = control room free volume, (ft3) fR = filter efficiency of the filter on the recirculation unit 60 = conversion factor, s/min 3600 = conversion factor, s/hr 24 = conversion factor, hr/day 0.02832 = conversion factor, m3/ft3 The coefficient matrix is:

0 L21 0 C = 0 ( d + s + L21 ) 0 0 Q (Lu + [1 f L ] Lf ) L21 (Lf + Lu ) / [ (Vc ) ( 0.02832)] + f R R c + d After solving for A(t), the integrated activity in each node can then be calculated.

15B-22 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15 B DOSE MODELS From the integrated activity, the doses to the operators in the control room can be calculated using the dose models given in section 15B.5.

15B-23 Rev: 25

San Onofre 2&3 FSAR Updated APPENDIX 15.10B

15. SECTION 15.10 APPENDICES APPENDIX 15.10B DOSE MODELS USED TO EVALUATE THE ENVIRONMENTAL CONSEQUENCES OF ACCIDENTS This Appendix 15.10B presents clarifications and additions to the Appendix 15B and Appendix 15G dose models used to evaluate environmental and control room dose consequences of accidents. The Appendix 15B models apply to those accidents addressed in Section 15B.1 that have been analyzed in accordance with the Technical Information Document (TID)-14844 methodology. The Appendix 15G models apply to those accidents addressed in Section 15G.1 that have been analyzed with the Alternative Source Term (AST) methodology.

15.10B.1 Clarifications to Existing Appendix 15B Dose Models Recent evaluations of offsite whole body gamma and beta skin immersion doses are determined using the Regulatory Guide 1.109 whole body gamma and beta skin dose conversion factors as presented in Table 15B-6. As noted in Section 15B.5, these same dose conversion factors are employed in control room dose evaluations. The Regulatory Guide 1.109 immersion dose conversion factors differ from values calculated using Regulatory Guide 1.4 formulae based on average gamma and beta disintegration energies, as listed in Table 15B-1, that were previously used in evaluating offsite immersion doses.

Modeling of the control room ventilation system has evolved from that presented in Table 15B-5 to reflect current plant design and operating procedures. Table 15.10B-1 summarizes these changes, including an updated control room volume, and updated minimum intake and maximum recirculation flow rates.

The control room dose models for direct containment and outside cloud doses have evolved from those described in Section 15B.5. The updated dose models for these radiation sources are discussed below:

A. Direct whole body gamma dose from the radioactivity present in the containment building (direct containment dose).

The containment is modeled by an equivalent volume cylindrical source having a diameter of 150 feet and height of 129.25 feet. The radioactivity present in the containment is assumed to be uniformly distributed in the cylindrical source.

Shielding is assumed to be provided by the 1/4-inch steel containment liner, and either the 4-foot concrete containment wall or the 3-foot 9-inch concrete containment dome. The penetration building lies between the containment and the control building; shielding credit is taken for the 2-foot penetration building concrete wall and the adjacent 2-foot 6-inch control building concrete wall. In addition, shielding credit is taken for a 2-inch fire partition wall which separates 15.10B-1 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated APPENDIX 15.10B the control room from the cable riser gallery adjacent to the penetration building.

The air spaces between these walls are also modeled.

No credit is taken for shielding afforded by the internal containment concrete structure, nor is credit taken for the internal control room fire separation walls and equipment.

B. Direct whole body gamma dose from the radioactive cloud surrounding the control room (outside cloud dose).

Leakage from the containment building, or any building, will result in the formation of a radioactive cloud. For conservatism it is assumed that this cloud surrounds the control room, entering adjacent areas which are not part of the control room HVAC envelope. Gamma radiation from this cloud can penetrate the control room ceiling and walls resulting in a whole body gamma dose to control room personnel. The cloud is modeled as a square cylinder with a 4000 foot radius and a 4000 foot height. The radius and height values ensure that dose contributions from the outer portion of the cloud are considered. The radioactivity present in the outside cloud is assumed to be uniformly distributed in the cylindrical source.

Radioactivity concentrations (Ci/m3) in the radioactive cloud surrounding the control room are the product of the building leak rate (Ci/s) and the control room atmospheric dispersion factor F/Q (s/m3). Calculations used to compute F/Q are presented in subsection 2.3.4. A tabulation of control room F/Qs is presented in table 15B-4.

Shielding is assumed to be provided by the concrete containment structures, the concrete safety equipment building wall adjacent to the control building, the control room concrete walls, floor and ceiling, and the auxiliary/radwaste building outer concrete walls, floors and roof. In addition, shielding is assumed to be provided by several of the internal control room fire partition walls. The air spaces between these walls, floor and ceilings are also modeled.

Table 15B-7 presents the release pathways for those accidents for which dose consequences have been evaluated. An additional analysis has been performed to evaluate control room habitability following a primary sample or instrument (letdown) line break. This analysis also considers the potential for secondary side activity releases during the post-accident plant cooldown. Table 15.10B-2 presents this accident=s leakage pathways.

15.10B-2 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated APPENDIX 15.10B Table 15.10B-1 CONTROL ROOM VENTILATION SYSTEM PARAMETERS Parameter Assumption Normal operation unfiltered intake rate (prior to CRIS initiating CREACUS)(a), standard ft3/min 5,820 Normal operation unfiltered recirculation rate (prior to CRIS initiating CREACUS), standard ft3/min 29,885 CREACUS intake rate, standard ft3/min (8+ hours) 2,200 (0-8 hours) 4,400 3

CREACUS recirculation rate, standard ft /min (8+ hours) 29,934 (0-8 hours) 59,869 3

Control room volume, standard ft 266,920 (a) Control Room Isolation Signal, and Control Room Emergency Air Cleanup System Table 15.10B-2 ADDITIONAL ACCIDENT LEAKAGE PATHWAYS Accident Pathway Legend(b)

Primary sample or instrument line break Reactor Coolant System  Atm(a) 

1. Primary Release Control Room A-D-E Steam Dump and Safety Valves 

2. Secondary Release Atm(a)  Control Room A-D-E (a) End of release path for offsite doses.

(b) Refer to figure 15B-1.

15.10B-3 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated APPENDIX 15.10B 15.10B.2 Additions to Existing Appendix 15B Dose Models The following subsections present activity concentration profiles used in Chapter 15 accident dose evaluations that have been analyzed with the Technical Information Document (TID)-

14844 methodology.

15.10B.2.1 Technical Specification Activity Limits Previous design basis analyses considered primary and secondary side releases based on primary reactor coolant and secondary side water and steam activity concentration profiles with one percent failed fuel. Standard Review Plan guidance recommends that activity releases be based on the maximum activity concentrations permitted by the technical specifications. Recent design basis analyses have followed the Standard Review Plan guidance.

15.10B.2.1.1 Activity at Technical Specification Limits The primary reactor coolant activity concentration profile used in recent Chapter 15 dose evaluations is for the conditions of 1.0 )Ci/gm Dose Equivalent I-131, and 100/r )Ci/gm average activity concentration for other non-iodine isotopes with half lives greater than 15 minutes, including tritium. The relative abundance of each isotope is based on a core average fuel burnup of 60 GWD/t.

The secondary side water activity concentration profile used in recent chapter 15 dose evaluations is for the condition of 0.1 )Ci/gm Dose Equivalent I-131. The relative abundance of each isotope is based on a core average fuel burnup of 60 GWD/t.

The secondary side steam non-noble gas activities are based on an iodine partition coefficient of 0.01, and a particulate partition coefficient of 0.002. The secondary side noble gas activity concentrations are based on primary to secondary leakage being at the Technical Specification limit of 0.5 gpm per steam generator (for a total of 1 gpm for both steam generators), with no retention of the noble gases in the steam generator liquid. The relative abundance of each isotope is based on a core average fuel burnup of 60 GWD/t.

15.10B.2.1.2 Reactor Coolant System Activity with an Iodine Spike 15.10B.2.1.2.1 Pre-Existing Iodine Spike At full power conditions, Technical Specifications permit an iodine spike equivalent to 60 )Ci/gm Dose Equivalent I-131 to exist for a limited period of time. When this iodine spike is modeled as being present at the beginning of an accident, it is referred to as a pre-existing iodine spike. For a pre-existing iodine spike, the reactor coolant system iodine activities are increased by a factor of 60 over the 1.0 )Ci/gm Dose Equivalent I-131 values. Non-iodine isotope activity concentrations are as discussed in section 15.10B.2.1.1.

15.10B-4 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated APPENDIX 15.10B 15.10B.2.1.2.2 Accident Induced (Concurrent) Iodine Spike If an accident results in a reactor coolant system depressurization, the depressurization may cause the iodine release rate from the fuel to increase. This is known as an accident induced, or concurrent, iodine spike. Figure 15.10B-1 shows the time dependent increase in RCS iodine activity concentration (from the initial value of 1.0 )Ci/gm Dose Equivalent I-131) for a factor of 500 increase in the iodine release rate from the fuel. Non-iodine isotope activity concentrations are as discussed in section 15.10B.2.1.1.

15.10B.2.2 Fuel Activity Inventories for Accident Analyses 15.10B.2.2.1 Fuel Rod Activity Inventory for Non-LOCA Transients Table 15.10B-3 lists the average volatile fission product activities for non-LOCA transients on a per fuel rod basis. This data reflects increases in Uranium-235 enrichments facilitating higher burnups, and is based on the following parameters:

a. average power per fuel rod does not exceed 68.045 kw (equivalent to 3390 MWt from a core containing 49,820 fuel rods).

b. fuel pellet enrichment does not exceed 5 weight percent U-235.

Table 15.10B-3 FUEL ROD VOLATILE FISSION PRODUCT ACTIVITY INVENTORY FOR NON-LOCA TRANSIENTS Isotope Activity (Curies/fuel rod)

Kr-83m 2.619 x 102 Kr-85 2.234 x 101 Kr-85m 5.833 x 102 Kr-87 1.147 x 103 Kr-88 1.621 x 103 Xe-131m 2.084 x 101 Xe-133m 1.172 x 102 Xe-133 3.666 x 103 Xe-135m 7.438 x 102 Xe-135 1.115 x 103 Xe-138 3.247 x 103 I-131 1.859 x 103 I-132 2.679 x 103 I-133 3.762 x 103 I-134 4.168 x 103 I-135 3.514 x 103 15.10B-5 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated APPENDIX 15.10B 15.10B.2.2.2 DELETED Table 15.10B-4 (Deleted) 15.10B.2.2.3 Core Activity Inventory for Loss of Coolant Accidents Table 15.10B-5 presents the core inventory of radioisotopes used in the original loss of coolant accident and CEA ejection dose analyses. This data is based on a core power level of 3560 MWt (i.e., 105% of nominal power), a one batch low enrichment core.

Table 15.10B-5 ORIGINAL CORE ACTIVITY INVENTORY FOR LOSS OF COOLANT ACCIDENTS Nuclide Activity (Ci) Nuclide Activity (Ci) Nuclide Activity (Ci)

Br-84 2.85 x 107 Mo-99 1.89 x 108 I-135 1.89 x 108 Br-85 3.99 x 107 Tc-99m 2.27 x 107 Xe-135m 5.51 x 107 Kr-85m 3.98 x 107 Ru-103 9.18 x 107 Xe-135 4.62 x 107 Kr-85 8.73 x 105 Ru-106 8.23 x 106 Cs-135 1.15 x 101 Kr-87 7.44 x 107 Te-129m 1.07 x 107 Cs-136 1.78 x 105 Kr-88 1.09 x 108 Te-129 3.29 x 107 Xe-137 1.80 x 108 Rb-88 1.10 x 108 I-129 2.08 x 100 Cs-137 4.15 x 106 Kr-89 1.41 x 108 I-131 8.96 x 107 Xe-138 1.79 x 108 Rb-89 1.46 x 108 Xe-131m 6.16 x 105 Cs-138 2.04 x 108 Sr-89 1.45 x 108 Te-132 1.33 x 108 Cs-140 1.81 x 108 Sr-90 9.27 x 106 I-132 1.33 x 108 La-140 1.95 x 108 Y-90 9.22 x 106 Te-133m 1.07 x 108 Ba-143 1.60 x 108 Sr-91 1.78 x 108 Te-133 1.13 x 108 La-143 1.81 x 108 Y-91m 1.05 x 108 I-133 2.06 x 108 Ce-143 1.81 x 108 Y-91 1.79 x 108 Xe-133 1.97 x 108 Pr-143 1.81 x 108 Y-95 1.87 x 108 Cs-134 1.03 x 106 Ce-144 1.26 x 108 Zr-95 1.87 x 108 Te-134 2.12 x 108 Pr-144 1.26 x 108 Nb-95 1.90 x 108 I-134 2.39 x 108 15.10B-6 Amended: April 2009 TL: E047998

San Onofre 2&3 FSAR Updated APPENDIX 15.10B Table 15.10B-6 presents the updated core inventory of radioisotopes used in the Chapter 15 loss of coolant accident dose analyses. This data is based on a two batch core in which the fresh fuel operates at 115% of nominal batch power and the once burned batch operated at 85% of nominal batch power. The core inventory is valid for the following conditions:

a) Core Power of no more than approximately 3458 MWt (= 102 percent x 3390 MWt) b) Assembly Average Enrichment of no less than 4.00 w/o Uranium-235 c) Cycle Length of no more than 635 EFPD d) Fresh Batch Power of no more than 1988.24 MWt e) Fresh fuel batch size of less than 109 assemblies.

Table 15.10B-6 UPDATED CORE ACTIVITY INVENTORY FOR LOSS OF COOLANT ACCIDENTS Nuclide Activity (Ci) Nuclide Activity (Ci) Nuclide Activity (Ci)

Br-84 1.98 x 107 Mo-99 1.72 x 108 I-135 1.79 x 108 Br-85 2.24 x 107 Tc-99m 1.51 x 108 Xe-135m 4.04 x 107 Kr-85m 2.25 x 107 Ru-103 1.49 x 108 Xe-135 3.93 x 107 Kr-85 9.57 x 105 Ru-106 5.09 x 107 Cs-135 3.62 x 101 Kr-87 4.44 x 107 Te-129m 5.88 x 106 Cs-136 5.59 x 106 Kr-88 6.16 x 107 Te-129 2.89 x 107 Xe-137 1.72 x 108 Rb-88 6.32 x 107 I-129 3.42 x 100 Cs-137 1.13 x 107 Kr-89 7.60 x 107 I-131 9.30 x 107 Xe-138 1.59 x 108 Rb-89 8.22 x 107 Xe-131m 1.02 x 106 Cs-138 1.73 x 108 Sr-89 8.74 x 107 Te-132 1.33 x 108 Cs-140 1.43 x 108 Sr-90 8.31 x 106 I-132 1.35 x 108 La-140 1.72 x 108 Y-90 8.66 x 106 Te-133m 8.44 x 107 Ba-143 1.20 x 108 Sr-91 1.08 x 108 Te-133 1.00 x 108 La-143 1.40 x 108 Y-91m 6.29 x 107 I-133 1.89 x 108 Ce-143 1.41 x 108 Y-91 1.14 x 108 Xe-133 1.90 x 108 Pr-143 1.38 x 108 Y-95 1.50 x 108 Cs-134 1.95 x 107 Ce-144 1.19 x 108 Zr-95 1.57 x 108 Te-134 1.62 x 108 Pr-144 1.20 x 108 Nb-95 1.59 x 108 I-134 2.08 x 108 15.10B.3 Clarifications to Appendix 15G Dose Models None.

15.10B.4 Additions to Appendix 15G Dose Models None.

15.10B-7 Amended: April 2009 TL: E047998

SCE ATTACHMENT 19 LICXSE AUIHO0ITY FILL COY 2 O..E UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON D. C. 20555 SOUTHERN CALIFORNIA EDISON COMPANY SAN DIEGO GAS AND ELECTRIC COMPANY THE CITY OF RIVERSIDE, CALIFORNIA THE CITY OF ANAHEIM, CALIFORNIA DOCKET NO. 50-361 SAN ONOFRE NUCLEAR GENERATING STATION UNIT 2 FACILITY OPERATING LICENSE License No NPF-10

1. The Nuclear Regulatory Commission (the Commission) having found that:

A. The application for license filed by the Southern California Edison Company, San Diego Gas and Electric Company, the City of Riverside, California and The City of Anaheim, California (the licensees) complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I. and all required notifications to other agencies or bodies have been duly made:

B. Construction of the San Onofre Nuclear Generating Station. Unit 2 (the facility), has been substantially completed in conformity with Construction Permit No. CPPR-97 and the application as amended. the provisions of the Act, and the regulations of the Commission:

--/ C. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission:

D. There is reasonable assurance: (i)that the activities authorized by this operating license can be conducted without endangering the health and safety of the public, and (ii)that such activities will be conducted in compliance with the regulations of the Commission set forth in 10 CFR Chapter I:

E. The Southern California Edison Company* is technically qualified to engage in the activities authorized by this operating license in accordance with the Commission's regulations set forth In 10 CFR Chapter I:

F. The licensees are financially qualified to engage in the activities authorized by this operating license in accordance with the Commission's regulations set forth in 10 CFR Chapter 1:

• The Southern California Edison Company is authorized to act as agent for the other co-owners and has exclusive responsibility and control over the physical construction, operation, and maintenance of the facility.

Amendment No. 185

<<X9 g 4 &6g~a~

G. The licensees have satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements", of the Commission's regulations; H. The issuance of this license will not be inimical to the common defense and security or to the health and safety of the public; I. After weighing the environmental, economic, technical, and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of Facility Operating License No. NPF-1O, subject to the condition for protection of the environment set forth herein, is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied; and J. The receipt, possession, and use of source, byproduct, and special nuclear material as authorized by this liicense will be in accordance with the Commission's regulations in 10 CFR Parts 30, 40 and 70.

2. Based on the foregoing findings and the Partial Initial Decision issued by the Atomic Safety and Licensing Board on January 11, 1982 regarding this facility, Facility Operating License No. NPF-10 is hereby issued to the Southern California Edison Company, the San Diego Gas and Electric Company, the City of Riverside, California and the City of Anaheim, California' to read as follows:

A. This license applies to the San Onofre Nuclear Generating Station, Unit 2, a pressurized water nuclear reactor and associated equipment (the facility), owned by the licensees. The facility is located in San Diego County, California, and is described in The Final Safety Analysis Report as supplemented and amended, and the Environmental Report as supplemented and amended.

B. Subject to the conditions and requirements incorporated herein, the Commission hereby licenses:

(1) Southern California Edison Company, San Diego Gas and Electric Company, the City of Riverside, California, and the City of Anaheim, California' to possess the facility at the designated location in San Diego County, California, in accordance with the procedures and limitations set fo~rth in this license; (2) Southern California Edison Company (SCE), pursuant to Section 103 of the Act and 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities", to possess, use, and operate the facility at the designated location in San Diego County, California, in accordance with the procedures and limitations set forth in this license; Amendment No. 44,-&5.209

'The City of Anaheim has transferred its ownership interests in the facility, and entitlement to facility output, to Southern California Edison Company, except that it retains its ownership interests in its spent nuclear fuel and the facility's independent spent fuel storage installation located on the facility's site. In addition, the City ofAnaheim retains financial responsibility for its spent fuel and for a portion of the facility's decommissioning costs. The City of Anaheim remains a licensee for purposes of its retained interests and liabilities.

-3 (3) SCE, pursuant to the Act and 10 CFR Part 70, to receive, possess, and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4) SCE, pursuant to the Act and 10 CFR Parts 30,40, and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5) SCE, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) SCE, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of San Onofre Nuclear Generating Station, Units 1 and 2 and by the decommissioning of San Onofre Nuclear Generating Station Unit 1.

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power level Southern California Edison Company (SCE) is authorized to operate the facility at reactor core power levels not in excess of full power (3438 megawatts thermal).

(2) Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 226, are hereby incorporated in the license.

Southern California Edison Company shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Amendment No. 226

(3) Antitrust Conditions SCE shall comply with the antitrust conditions delineated in Appendix C to this license.

(4) Containment Tendon Surveillance (Section *3.8.1. SER. SSER Deleted by Amendment No. 37 (5) Environmental Qualification (Section 3.11. SER. SSER #3, SSER Deleted by Amendment No. 60 (6) High Burnup Fission Gas Release (Section 4.2.2.2. SER)

Deleted by Amendment No. 185 (7) Low Temperature Overpressurization Protection (Section 5.2.2.2. SER)

Deleted by Amendment No. 185 (8) Control Room Pressurization Capability (Section 6.4. SER.

SSER #5)

Deleted by Amendment No. 185 (9) Seismic Trin System (Section 7.2.5. SSER #4)

Deleted by Amendment No. 185 (10) Volume Control Tank Control Logic (Section 7.3.5. SSER #4)

Deleted by Amendment No. 185 (11) Compliance with Regulatorv Guide 1.97 (Section 7.5.1, SER.

SSER #5)

Deleted by Amendment No. 185 (12) Control System Failures (Section 7.7. SSER #4)

Deleted by Amendment No. 185 (13) Diesel Generator Modifications (Section 8.3.1. SER)

Deleted by Amendment No. 185

• The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed.

Amendment No. 185 Nwj (i~- 8~o gSlDS

(14) Fire Protection (Section 9.5.1, SER. SSER #4. SSER X5.

Section 1.12. SSER #5: SE dated November 15, 1982: Revision 1 to Updated Fire Hazards Analysis Evaluation dated June 29, 1988)

SCE shall implement and maintain in effect all provisions of the approved fire protection program. This program shall be (1)as described in the Updated Fire Hazards Analysis through Revision 3 as revised by letters to the NRC dated May 31, July 22. and November 20, 1987 and January 21, February 22.

and April 21, 1988; and (2)as approved in the NRC staff's Safety Evaluation Report (SER) (NUREG-0712) dated February 1981: Supplements 4 and 5 to the SER, dated January 1982 and February 1982, respectively: and the safety evaluation dated November 15, 1982; as supplemented and amended by the Updated Fire Hazards Analysis Eval uation for San Onofre 2 and 3.

Revision 1 dated June 29. 1988. SCE may make changes to the agproved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

(15) Turbine Disc Inspection (Section 10.2.2. SER)

Deleted by Amendment No. 185 (16) Radioactive Waste System (Section 11.1, SER. SSER #5)

Deleted by Amendment No. 185 (17) PurQe System Monitors (Section 11.3. SER. SSER #5)

Deleted by Amendment No. 185 (18) Initial Test ProQram (Section 14. SER)

Deleted by Amendment No. 185 (19) NUREG-0737 Conditions (Section 22)

a. Shift Technical Advisor (I.A.1.1. SSER #1)

Deleted by Amendment No. 185

b. Shift Manning (I.A.1.3. SSER #1, SSER #5)

Deleted by Amendment No. 147

c. Independent Safety Engineering Group (1.B.1.2. SSER #1)

Deleted by Amendment No. 185

d. Procedures for Transients and Accidents (I.C.1. SSER #1.

SSER #2. SSER #5)

Deleted by Amendment No. 185 Amendment No. 185 c QZc&b 06 &_9_

e. Procedures for Verifying Correct Performance of Operating Activities (U.C.6. SSER #1)

Deleted by Amendment No. 185 I

f. Control Room Design Review (I.D.1. SSER #1)

Deleted by Amendment No. 185 I

9. Special Low Power Testing and Training (I.G.1. SSER #1)

Deleted by Amendment No. 185

h. Reactor Coolant System Vents (II.B.1). SSER #1 , SSER t4l Deleted by Amendment No. 185

1. Post-Accident Sampling System (NUREG-0737 Item II.B.3)

Deleted by Amendment No. 178 I i- Safety Valve Test Requirements (II.D.1, SSER #1)

Deleted by Amendment No. 185

k. Direct Indication of Safety Valve Position (JI.D.3, SSER

~11 Deleted by Amendment No. 185

1. AFW Pump 48-hour Endurance Test (II.E.1.1, SSER #1)

Deleted by Amendment No. 185

m. Emergency Power Supplv for Pressurizer Heaters (Il.E.3.1. SSER #1. SSER #5)

Deleted by Amendment No. 185

n. Additional Monitoring Instrumentation (II.F.1, SSER #1.

SSER #4)

Deleted by Amendment No. 185

0. ICC Instrumentation (II.F.2. SSER #1, SSER #2. SSER #4)

Deleted by Amendment No. 185 p- Voiding in the Reactor Coolant System (II.K.2.17, SSER

-#I. SSER #5)

Deleted by Amendment No. 185 I q- Revised Model for Small-Break LOCAs (II.K.3.30. SSER #1, SSER #4.SSER #5 Deleted by Amendment No. 185 I Amendment No. 185 Cat-~w A, o6 Q-g

r. Plant-Specific Calculations for Compliance with 10 CFR Section 50.46 (l1.K.3.31, SSER #1)

Deleted by Amendment No. 185 S. Improving Licensee Emergency Preparedness (III.A.2, SSER#1, SSER #5)

Deleted by Amendment No. 185 (20) Surveillance Program (Section 1.12, SSER #5)

Deleted by Amendment No. 185 (21) Laboratory Instrumentation (Section 1.12, SSER #5)

Deleted by Amendment No. 185 (22) Design Verification Program (Section 3.7.4. SSER #5)

Deleted by Amendment No. 185 (23) Emergency Preparedness Conditions Deleted by Amendment No. 185 (24) RCS Depressurization System (PORV's)

Deleted by Amendment No. 185 (25) Qualification of Auxiliary Feedwater (AFW) Pump Motor Bearings Deleted by Amendment No. 185 (26) Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas:

(a) Fire fighting response strategy with the following elements:

1. Pre-defined coordinated fire response strategy and guidance

2. Assessment of mutual aid fire fighting assets

3. Designated staging areas for equipment and materials

4. Command and control

5. Training of response personnel (b) Operations to mitigate fuel damage considering the following:

1. Protection and use of personnel assets

2. Communications

3. Minimizing fire spread

4. Procedures for implementing integrated fire response strategy

5. Identification of readily-available pre-staged equipment Amendment No. 185 Revised by letter dated July 26, 2007

6. Training on integrated fire response strategy

7. Spent fuel pool mitigation measures (c) Actions to minimize release to include consideration of:

1. Water spray scrubbing

2. Dose to onsite responders (27) Upon implementation of Amendment No. 214 adopting TSTF-448, l Revision 3, the determination of control room envelope (CRE) unfiltered air l inleakage as required by SR 3.7.11.4, in accordance with TS 5.5.2.16.c.(i), l the assessment of CRE habitability as required by Specification l 5.5.2.16.c.(ii), and the measurement of CRE pressure as required by l Specification 5.5.2.16.d, shall be considered met. Following l implementation: l l

(a) The first performance of SR 3.7.11.4, in accordance with l Specification 5.5.2.16.c.(i), shall be within the specified frequency l of 6 years, plus the 18-month allowance of SR 3.0.2, as measured l from May 18, 2004, the date of the most recent successful tracer l gas test, as stated in the September 17, 2004 letter response to l Generic Letter 2003-01, or within the next 18 months if the time l period since the most recent successful tracer gas test is greater l than 6 years. l l

(b) The first performance of the periodic assessment of CRE l habitability, Specification 5.5.2.16.c.(ii), shall be within 3 years, plus l the 9-month allowance of SR 3.0.2, as measured from May 18, l 2004, the date of the most recent successful tracer gas test, as l stated in the September 17, 2004, letter response to Generic Letter l 2003-01, or within the next 9 months if the time period since the l most recent successful tracer gas is greater than 3 years. l l

(c) The first performance of the periodic measurement of CRE l pressure, Specification 5.5.2.16.d, shall be within 6 months. l D. Exemptions to certain requirements of Appendices G, H and J to 10 CFR Part 50 are described in the Office of Nuclear Reactor Regulation's Safety Evaluation Report. These exemptions are authorized by law and will not endanger life or property or the common defense and security and are otherwise in the public interest. Therefore, these exemptions are hereby granted. The facility will operate, to the extent authorized herein, in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission.

Amendment No. 214 l Revised by letter dated July 26, 2007

-9 E. SCE shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contain Safeguards Information protected under 10 CFR 73.21 is entitled: "San Onofre Nuclear Generating Station Security, Training and Qualification, and Safeguards Contingency Plan, Revision 2" submitted by letter dated May 15, 2006. SCE shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The SONGS CSP was approved by License Amendment No. 225.

F. This license is subject to the following additional condition for the protection of the environment:

Before engaging in activities that may result in a significant adverse environmental impact that was not evaluated or that is significantly greater than that evaluated in the Final Environmental Statement, SCE shall provide a written notification of such activities to the NRC Office of Nuclear Reactor Regulation and receive written approval from that office before proceeding with such activities.

G. DELETED H. SCE shall notify the Commission, as soon as possible but not later than one hour, of any accident at this facility which could result in an unplanned release of quantities of fission products in excess of allowable limits for normal operation established by the Commission.

I. SCE shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.

J. This license is effective as of the date of issuance and shall expire at midnight on February 16, 2022.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed by Harold R. Denton Harold R. Denton, Director Office of Nuclear Reactor Regulation

Enclosures:

1. Appendix A (Technical SpeCifications)

2. Appendix B (Environmental Protection Plan)

3. Appendix C (Antitrust Conditions)

Date of Issuance: FEB 16 1982 "On September 29, 1983, the Safeguards Contingency Plan was made a separate, companion document to the Physical Security Plan pursuant to the authority of 10 CFR 50.54.

Amendment No. 225 Revised by letter dated Marsh 6, 2007

SCE ATTACHMENT 20 NEI 96-07, Revision 1 Nuclear Energy Institute GUIDELINES FOR 10 CFR 50.59 IMPLEMENTATION November 2000

NEI 96-07, Revision 1 November 2000 TABLE OF CONTENTS FOREWORD ........................................................................................................................................................... i 1 INTRODUCTION ......................................................................................................................................... 1 2 DEFENSE IN DEPTH DESIGN PHILOSOPHY AND 10 CFR 50.59 ................................................. 7 3 DEFINITIONS AND APPLICABILITY OF TERMS ............................................................................... 9 4 IMPLEMENTATION GUIDANCE .......................................................................................................... 23 4.1 APPLICABILITY ............................................................................................... 23 4.2 SCREENING ..................................................................................................... 29 4.3 EVALUATION PROCESS ................................................................................... 41 4.4 APPLYING 10 CFR 50.59 TO COMPENSATORY ACTIONS TO ADDRESS NONCONFORMING OR DEGRADED CONDITIONS ............................ 70 4.5 DISPOSITION OF 10 CFR 50.59 EVALUATIONS.............................................. 72 5 DOCUMENTATION AND REPORTING ...............................................................................................73 APPENDICES A. 10 CFR 50.59CHANGES, TESTS, AND EXPERIMENTS.. ......................................................... A-1 B. GUIDELINES FOR 10 CFR 72.48 IMPLEMENTATION (FUTURE) ............................. ... B-1 iii

NEI 96-07, Revision 1 November 2000 that are not explicitly incorporated by reference are not considered part of the UFSAR and therefore are not subject to control under 10 CFR 50.59.

Per 10 CFR 50.59(c)(4), licensees are not required to apply 10 CFR 50.59 to UFSAR information that is subject to other specific change control regulations. For example, licensee quality assurance programs, emergency plans and security plans are controlled by 10 CFR 50.54(a), (p) and (q),

respectively.

Per 10 CFR 50.59(c)(3), the FSAR (as updated), for purposes of 10 CFR 50.59, also includes UFSAR update pages approved by the licensee for incorporation in the UFSAR since the last required update was submitted per 10 CFR 50.71(e). The intent of this requirement is to ensure that decisions about proposed activities are made with the most complete and accurate information available. Pending UFSAR revisions may be relevant to a future activity that involves that part of the UFSAR. Therefore, pending UFSAR revisions to reflect completed activities that have received final approval for incorporation in the next required update should be considered as part of the UFSAR for purposes of 10 CFR 50.59 screenings and evaluations, as appropriate. Appropriate configuration management mechanisms should be in place to identify and assess interactions between concurrent changes affecting the same SSCs or the same portion of the UFSAR.

Guidance on the required content of UFSAR updates is provided in Regulatory Guide 1.181 and NEI 98-03, Revision 1, Guidelines for Updating FSARs, June 1999.

3.8 INPUT PARAMETERS Definition:

Input parameters are those values derived directly from the physical characteristics of SSC or processes in the plant, including flow rates, temperatures, pressures, dimensions or measurements (e.g., volume, weight, size, etc.), and system response times.

Discussion:

The principal intent of this definition is to distinguish methods of evaluation from evaluation input parameters. Changes to methods of evaluation described in the UFSAR (see Section 3.10) are evaluated under criterion 10 CFR 50.59(c)(2)(viii), whereas changes to input parameters described in the FSAR are considered changes to the facility that would be evaluated under the other seven criteria of 10 CFR 50.59(c)(2), but not criterion (c)(2)(viii).

17

NEI 96-07, Revision 1 November 2000 If a methodology permits the licensee to establish the value of an input parameter on the basis of plant-specific considerations, then that value is an input to the methodology, not part of the methodology. On the other hand, an input parameter is considered to be an element of the methodology if:

The method of evaluation includes a methodology describing how to select the value of an input parameter to yield adequately conservative results. However, if a licensee opts to use a value more conservative than that required by the selection method, reduction in that conservatism should be evaluated as an input parameter change, not a change in methodology.

The development or approval of a methodology was predicated on the degree of conservatism in a particular input parameter or set of input parameters. In other words, if certain elements of a methodology or model were accepted on the basis of the conservatism of a selected input value, then that input value is considered an element of the methodology.

Examples illustrating the treatment of input parameters are provided in Section 4.2.1.3.

Section 4.3.8 provides guidance and examples to describe the specific elements of evaluation methodology that would require evaluation under 10 CFR 50.59(c)(2)(viii) and to clearly distinguish these from specific types of input parameters that are controlled by the other seven criteria of 10 CFR 50.59(c)(2).

3.9 MALFUNCTION OF AN SSC IMPORTANT TO SAFETY Definition:

Malfunction of SSCs important to safety means the failure of SSCs to perform their intended design functions described in the UFSAR (whether or not classified as safety-related in accordance with 10 CFR 50, Appendix B).

Discussion:

Guidance and examples for applying this definition are provided in Section 4.3.

18

NEI 96-07, Revision 1 November 2000 3.13 SCREENING Definition:

Screening is the process for determining whether a proposed activity requires a 10 CFR 50.59 evaluation to be performed.

Discussion:

Screening is that part of the 10 CFR 50.59 process that determines whether a 10 CFR 50.59 evaluation is required prior to implementing a proposed activity.

The definitions of change, facility as described, procedures as described and test or experiment not described constitute criteria for the 10 CFR 50.59 screening process. Activities that do not meet these criteria are said to screen out from further review under 10 CFR 50.59, i.e., may be implemented without a 10 CFR 50.59 evaluation.

Engineering and technical information concerning a proposed activity may be used along with other information as the basis for determining if the activity screens out or requires a 10 CFR 50.59 evaluation.

Further discussion and guidance on screening are provided in Section 4.2.

3.14 TESTS OR EXPERIMENTS NOT DESCRIBED IN THE FSAR (AS UPDATED)

Definition:

Tests or experiments not described in the final safety analysis report (as updated) means any activity where any structure, system, or component is utilized or controlled in a manner which is either:

Q Outside the reference bounds of the design bases as described in the UFSAR, or Q Inconsistent with the analyses or descriptions in the UFSAR.

Discussion:

10 CFR 50.59 is applied to tests or experiments not described in the UFSAR.

The intent of the definition is to ensure that tests or experiments that put the facility in a situation that has not previously been evaluated (e.g.,

unanalyzed system alignments) or that could affect the capability of SSCs to perform their intended design functions (e.g., high flow rates, high 22

NEI 96-07, Revision 1 November 2000 temperatures) are evaluated before they are conducted to determine if prior NRC approval is required.

Maintenance-related testing is assessed and managed under 10 CFR 50.65(a)(4), as discussed in Section 4.1.2. 10 CFR 50.59 screening of tests and experiments unrelated to maintenance is discussed in Section 4.2.2.

Examples of tests unrelated to maintenance and thus subject to 10 CFR 50.59 include (1) most core physics testing, (2) room heat-up testing to validate a design/analysis input, and (3) testing to help determine which of two redesign alternatives to pursue.

4 IMPLEMENTATION GUIDANCE Licensees may determine applicability and screen activities to determine if 10 CFR 50.59 evaluations are required as described in Sections 4.1 and 4.2, or equivalent manner.

4.1 APPLICABILITY As stated in Section (b) of 10 CFR 50.59, the rule applies to each holder of a license authorizing operation of a production or utilization facility, including the holder of a license authorizing operation of a nuclear power reactor that has submitted a certification of permanent cessation of operations required under 10 CFR 50.82(a)(1) or a reactor licensee whose license has been amended to allow possession but not operation of the facility.

4.1.1 Applicability to Licensee Activities 10 CFR 50.59 is applicable to tests or experiments not described in the UFSAR and to changes to the facility or procedures as described in the UFSAR, including changes made in response to new requirements or generic communications, except as noted below:

Q Per 10 CFR 50.59(c)(1)(i), proposed activities that require a change to the technical specifications must be made via the license amendment process, 10 CFR 50.90. Aspects of proposed activities that are not directly related to the required technical specification change are subject to 10 CFR 50.59.

Q To reduce duplication of effort, 10 CFR 50.59(c)(4) specifically excludes from the scope of 10 CFR 50.59 changes to the facility or procedures that are controlled by other more specific requirements and criteria established by regulation. For example, 10 CFR 50.54, which was promulgated after 23

NEI 96-07, Revision 1 November 2000 changes to the fire protection program do not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. An evaluation performed in accordance with the license condition should include an assessment of the impact of the change on the existing fire hazards analysis for the area, as is current practice. The assessment should address the effects on combustible loading and distribution and should consider whether circuits or components, including associated circuits, for a train of equipment needed for safe shutdown could be affected, or whether a new element could be introduced into the area.

Under the standard license condition, approved fire protection program documents (e.g., fire hazards analysis) are incorporated in the UFSAR, and as such, changes to this information are subject to 10 CFR 50.71(e) reporting requirements.

4.2 SCREENING Once it has been determined that 10 CFR 50.59 is applicable to a proposed activity, screening is performed to determine if the activity should be evaluated against the evaluation criteria of 10 CFR 50.59(c)(2).

Engineering, design and other technical information concerning the activity and affected SSCs should be used to assess whether the activity is a test or experiment not described in the UFSAR or a modification, addition or removal (i.e., change) that affects:

Q A design function of an SSC Q A method of performing or controlling the design function, or Q An evaluation for demonstrating that intended design functions will be accomplished.

Sections 4.2.1 and 4.2.2 provide guidance and examples for determining whether an activity is (1) a change to the facility or procedures as described in the UFSAR or (2) a test or experiment not described in the UFSAR. If an activity is determined to be neither, then it screens out and may be implemented without further evaluation under 10 CFR 50.59. Activities that are screened out from further evaluation under 10 CFR 50.59 should be documented as discussed in Section 4.2.3.

Each element of a proposed activity must be screened except in instances where linking elements of an activity is appropriate, in which case the linked elements can be considered together. A test for linking elements of proposed changes is interdependence.

29

NEI 96-07, Revision 1 November 2000 It is appropriate for discrete elements to be considered together if (1) they are interdependent as in the case where a modification to a system or component necessitates additional changes to other systems or procedures; or (2) they are performed collectively to address a design or operational issue. For example, a pump upgrade modification may also necessitate a change to a support system, such as cooling water.

If concurrent changes are being made that are not linked, each must be screened separately and independently of each other.

Activities that screen out may nonetheless require UFSAR information to be updated. Licensees should provide updated UFSAR information to the NRC in accordance with 10 CFR50.71(e).

Specific guidance for applying 10 CFR 50.59 to temporary changes proposed as compensatory actions for degraded or nonconforming conditions is provided in Section 4.4.

4.2.1 Is the Activity a Change to the Facility or Procedures as Described in the UFSAR?

To determine whether or not a proposed activity affects a design function, method of performing or controlling a design function or an evaluation that demonstrates that design functions will be accomplished, a thorough understanding of the proposed activity is essential. A given activity may have both direct and indirect effects that the screening review must consider.

The following questions illustrate a range of effects that may stem from a proposed activity:

Does the activity decrease the reliability of an SSC design function, including either functions whose failure would initiate a transient/

accident or functions that are relied upon for mitigation?

Does the activity reduce existing redundancy, diversity or defense-in-depth?

Q Does the activity add or delete an automatic or manual design function of the SSC?

Q Does the activity convert a feature that was automatic to manual or vice versa?

30

NEI 96-07, Revision 1 November 2000 Q Does the activity introduce an unwanted or previously unreviewed system or materials interaction?

Q Does the activity adversely affect the ability or response time to perform required actions, e.g., alter equipment access or add steps necessary for performing tasks?

Q Does the activity degrade the seismic or environmental qualification of the SSC?

Q Does the activity adversely affect other units at a multiple unit site?

Q Does the activity affect a method of evaluation used in establishing the design bases or in the safety analyses?

Q For activities affecting SSCs, procedures, or methods of evaluation that are not described in the UFSAR, does the change have an indirect effect on electrical distribution, structural integrity, environmental conditions or other UFSAR-described design functions?

Per the definition of change discussed in Section 3.3, 10 CFR 50.59 is applicable to additions as well as to changes to and removals from the facility or procedures. Additions should be screened for their effects on the existing facility and procedures as described in the UFSAR and, if required, a 10 CFR 50.59 evaluation should be performed. NEI 98-03 provides guidance for determining whether additions to the facility and procedures should be reflected in the UFSAR per 10 CFR 50.71(e).

Consistent with historical practice, changes affecting SSCs or functions not described in the UFSAR must be screened for their effects (so-called indirect effects) on UFSAR-described design functions. A 10 CFR 50.59 evaluation is required when such changes adversely affect a UFSAR-described design function, as described below.

Screening for Adverse Effects A 10 CFR 50.59 evaluation is required for changes that adversely affect design functions, methods used to perform or control design functions, or evaluations that demonstrate that intended design functions will be accomplished (i.e., adverse changes). Changes that have none of these effects, or have positive effects, may be screened out because only adverse changes have the potential to increase the likelihood of malfunctions, 31

NEI 96-07, Revision 1 November 2000 increase consequences, create new accidents or otherwise meet the 10 CFR 50.59 evaluation criteria. 3 Per the definition of design function, SSCs may have preventive, as well as mitigative, design functions. Adverse changes to either must be screened in.

Thus a change that decreases the reliability of a function whose failure could initiate an accident would be considered to adversely affect a design function and would screen in. In this regard, changes that would relax the manner in which Code requirements are met for certain SSCs should be screened for adverse effects on design function. Similarly, changes that would introduce a new type of accident or malfunction would screen in. This reflects an overlap between the technical/engineering (safety) review of the change and 10 CFR 50.59. This overlap reflects that these considerations are important to both the safety and regulatory reviews.

If a change has both positive and adverse effects, the change should be screened in. The 10 CFR 50.59 evaluation should focus on the adverse effects.

The screening process is not concerned with the magnitude of adverse effects that are identified. Any change that adversely affects a UFSAR-described design function, method of performing or controlling design functions, or evaluation that demonstrates that intended design functions will be accomplished is screened in. The magnitude of the adverse effect (e.g., is the minimal increase standard met?) is the focus of the 10 CFR 50.59 evaluation process.

Screening determinations are made based on the engineering/technical information supporting the change. The screening focus on design functions, etc., ensures the essential distinction between (1) 10 CFR 50.59 screenings, and (2) 10 CFR 50.59 evaluations, which focus on whether changes meet any of the eight criteria in 10 CFR 50.59(c)(2). Technical/engineering information, e.g., design evaluations, etc., that demonstrates changes have no adverse effect on UFSAR-described design functions, methods of performing or controlling design functions, or evaluations that demonstrate that intended design functions will be accomplished may be used as basis for screening out the change. If the effect of a change is such that existing safety analyses would no longer be bounding and therefore UFSAR safety analyses must be re-run to demonstrate that all required safety functions and design requirements are met, the change is considered to be adverse and must be screened in. The revised safety analyses may be used in support of the required 10 CFR 50.59 evaluation of such changes.

3 Note that as discussed in Section 4.2.1.1, any change that alters a design basis limit for a fission product barrierpositively or negativelyis considered adverse and must be screened in.

32

NEI 96-07, Revision 1 November 2000 Changes that entail update of safety analyses to reflect improved performance, capacity, timing, etc., resulting from a change (beneficial effects on design functions) are not considered adverse and need not be screened in, even though the change calls for safety analyses to be updated. For example, a change that improves the closure time of main control room isolation dampers reduces the calculated dose to operators, and UFSAR dose consequence analyses are to be updated as a result. In this case, the dose analyses are being revised to reflect the lower dose for the main control room, not to demonstrate that GDC limits continue to be met. A change that would adversely affect the design function of the dampers (post-accident isolation of the main control room) and increase the existing calculated dose to operators would be considered adverse and would screen in. In this case, the dose analyses must be re-run to ensure that GDC limits continue to be met. The revised analyses would be used in support of the 10 CFR 50.59 evaluation to determine if the increase exceeds the minimal standard and requires prior NRC approval.

To further illustrate the distinction between 10 CFR 50.59 screening and evaluation, consider the example of a change to a diesel generator-starting relay that delays the diesel start time from 10 seconds to 12 seconds. The UFSAR-described design function credited in the ECCS analyses is for the diesel to start within 12 seconds. This change would screen out because it is apparent that the change will not adversely affect the diesel generator design function credited in the ECCS analyses (ECCS analyses remain valid).

However, a change that would delay the diesels start time to 13 seconds would screen in because the change adversely effects the design function (to start in 12 seconds). Such a change would screen in even if technical/engineering information supporting the change includes revised safety analyses that demonstrate all required safety functions supported by the diesel, e.g., core heat removal, containment isolation, containment cooling, etc., are satisfied and that applicable dose limits continue to be met.

While this change may be acceptable with respect to performance of required safety functions and meeting design requirements, the analyses necessary to demonstrate acceptability are beyond the scope/intent of 10 CFR 50.59 screening reviews. Thus a 10 CFR 50.59 evaluation would be required. The revised safety analyses would be used in support of the 10 CFR 50.59 evaluation to determine whether any of the evaluation criteria are met such that prior NRC approval is required for the change.

Additional specific guidance for identifying adverse effects due to a procedure or methodology change is provided in subsections 4.2.1.2 and 4.2.1.3, respectively.

33

NEI 96-07, Revision 1 November 2000 4.2.1.1 Screening of Changes to the Facility as Described in the UFSAR Screening to determine that a 10 CFR 50.59 evaluation is required is straightforward when a change adversely affects an SSC design function, method of performing or controlling a design function, or evaluation that demonstrates intended design functions will be accomplished as described in the UFSAR.

However, a facility also contains many SSCs not described in the UFSAR.

These can be components, subcomponents of larger components or even entire systems. Changes affecting SSCs that are not explicitly described in the UFSAR can have the potential to adversely affect SSC design functions that are described and thus may require a 10 CFR 50.59 evaluation. In such cases, the approach for determining whether a change involves a change to the facility as described in the UFSAR is to consider the larger, UFSAR-described SSC of which the SSC being modified is a part. If for the larger SSC, the change adversely affects a UFSAR-described design function, method of performing or controlling the design function, or an evaluation demonstrating that intended design functions will be accomplished, then a 10 CFR 50.59 evaluation is required.

Another important consideration is that a change to nonsafety-related SSCs not described in the UFSAR can indirectly affect the capability of SSCs to perform their UFSAR-described design function(s). For example, increasing the heat load on a non safety-related heat exchanger could compromise the cooling systems ability to cool safety-related equipment.

Seismic qualification, missile protection, flooding protection, fire protection, environmental qualification, high energy line break and masonry block walls are some of the areas where changes to nonsafety-related SSCs, whether or not described in the UFSAR, can affect the UFSAR-described design function of SSCs through indirect or secondary effects.

Equivalent replacement is a type of change to the facility that does not alter the design functions of SSCs. Licensee equivalence assessments, e.g.,

consideration of performance/operating characteristics and other factors, may thus form the basis for screening determinations that no 10 CFR 50.59 evaluation is required.

As discussed in Section 4.2.1, only proposed changes to SSCs that would, based on supporting engineering and technical information, have adverse effects on design functions require evaluation under 10 CFR 50.59. Changes that have positive or no effect on design functions may generally be screened out. In addition, any change to a design bases limit for a fission product barrier must be considered adverse and screened in. This is because 10 CFR 34

NEI 96-07, Revision 1 November 2000 50.59(c)(2)(vii) requires prior NRC approval any time a proposed change would exceed or alter a design bases limit for a fission product barrier.

The following examples illustrate the 10 CFR 50.59 screening process as applied to proposed facility changes:

Example 1 A licensee proposes to replace a relay in the overspeed trip circuit of an emergency diesel generator with a nonequivalent relay. The relay is not described in the UFSAR, but the design functions of the overspeed trip circuit and the emergency diesel generator are. Based on engineering/technical information supporting the change, the licensee determines if replacing the relay would adversely affect the design function of either the overspeed trip circuit or EDG. If the licensee concludes that the change would not adversely affect the UFSAR-described design function of the circuit or EDG, then this determination would form the basis for screening out the change, and no 10 CFR 50.59 evaluation would be required.

Example 2 A licensee proposes a nonequivalent change to the operator on one of the safety injection accumulator isolation valves. The UFSAR describes that these isolation valves are open with their circuit breakers open during normal operation. These are motor operated, safety-related valves required for pressure boundary integrity and to remain open so that flow to the RCS will occur during a LOCA as RCS pressure drops below ~600 psi. They are remotely closed during a normal shutdown so as to not inject when not required. Technical/engineering work supporting this change ensures that the replacement operator is capable of performing the functions of the existing operator and will not adversely affect the connected Class 1E bus or diesel. This change would screen out because (1) the valve operator does not perform, support or impact the UFSAR-described design function (to ensure pressure boundary integrity and remain open when required) that supports safety injection performance credited in the safety analyses, and (2) the change does not adversely affect other SSC design functions (e.g., of the Class 1E bus).

If the proposed change was to configure the valve as a normally closed valve that automatically opens on loss of reactor coolant system pressure, 10 CFR 50.59 evaluation would be required because the change would adversely affect the reliability of the safety injection function as credited in the safety analyses.

35

NEI 96-07, Revision 1 November 2000 Example 3 A licensee proposes to replace a globe valve with a ball valve in a vent/drain application to reduce the propensity of this valve to leak. The UFSAR-described design function of this valve is to maintain the integrity of the system boundary when closed. The vent/drain function of the valve does not relate to design functions credited in the safety analyses, and the licensee has determined that a ball valve is adequate to support the vent/drain function and is superior to the globe valve in terms of its isolation function. Thus the proposed change affects the design of the existing vent/drain valvenot the design function (pressure boundary integrity) that supports system performance credited in the safety analysesand evaluation/reporting under 10 CFR 50.59 is not required. The screening determination should be documented, and the UFSAR should be updated per 10 CFR 50.71(e) to reflect the change.

Example 4 The bolts for retaining a rupture disk are being replaced with bolts of a different material and fewer threads, but equivalent load capacity and strength, such that the rupture disk will still relieve at the same pressure as before the change. Because the replacement bolts are equivalent to the original bolts, the design function of the rupture disk (to relieve at a specified pressure) is unaffected, and this activity may be screened out as an equivalent change.

4.2.1.2 Screening of Changes to Procedures as Described in the UFSAR Changes are screened in (i.e., require a 10 CFR 50.59 evaluation) if they adversely affect how SSC design functions are performed or controlled (including changes to UFSAR-described procedures, assumed operator actions and response times). Proposed changes that are determined to have positive or no effect on how SSC design functions are performed or controlled may be screened out.

For purposes of 10 CFR 50.59 screening, changes that fundamentally alter (replace) the existing means of performing or controlling design functions should be conservatively treated as adverse and screened in. Such changes include replacement of automatic action by manual action (or vice versa),

changes to the man-machine interface, changing a valve from locked closed to administratively closed and similar changes.

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NEI 96-07, Revision 1 November 2000 The following examples illustrate the 10 CFR 50.59 screening process as applied to proposed changes affecting how SSC design functions are performed or controlled:

Example 1 Emergency operating procedures include operator actions and response times associated with response to design basis events, which are described in the UFSAR, but also address operator actions for severe accident scenarios that are outside the design basis and not described in the UFSAR. A change would screen out at this step if the change was to those procedures or parts of procedures dealing with operator actions during severe accidents.

Example 2 If the UFSAR description of the reactor start-up procedure contains eight fundamental sequences, the licensee's decision to eliminate one of the sequences would screen in. On the other hand, if the licensee consolidated the eight fundamental sequences and did not affect the method of controlling or performing reactor start-up, the change would screen out.

Example 3 The UFSAR states that a particular flow path is isolated by a locked closed valve when not in use. A procedure change would remove the lock from this valve such that it becomes a normally closed valve. In this case, the design function is to remain closed, and the method of performing the design function has fundamentally changed from locked closed to administratively closed. Thus this change would screen in and require a 10 CFR 50.59 evaluation to be performed.

Example 4 Operations proposes to revise its procedures to change from 8-hour shifts to 12-hour shifts. This change results in mid-shift rounds being conducted every 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as opposed to every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The UFSAR describes high energy line breaks including mitigation criteria. Operator action to detect and terminate the line break is described in the UFSAR, which specifically states that 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is assumed for the pipe break to go undetected before it would be identified during operator mid-shift rounds. The change from 4 to 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> rounds is a change to a procedure as described in the UFSAR that adversely affects the timing of operator actions credited in the safety analyses for limiting the effects of high energy line breaks. Therefore, this change screens in, and a 10 CFR 50.59 evaluation is required.

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NEI 96-07, Revision 1 November 2000 4.2.1.3 Screening Changes to UFSAR Methods of Evaluation As discussed in Section 3.6, methods of evaluation included in the UFSAR to demonstrate that intended SSC design functions will be accomplished are considered part of the facility as described in the UFSAR. Thus use of new or revised methods of evaluation (as defined in Section 3.10) is considered to be a change that is controlled by 10 CFR 50.59 and needs to be considered as part of this screening step. Adverse changes to elements of a method of evaluation included in the UFSAR, or use of an alternative method, must be evaluated under 10 CFR 50.59(c)(2)(viii) to determine if prior NRC approval is required (see Section 4.3.8). Changes to methods of evaluation (only) do not require evaluation against the first seven criteria.

Changes to methods of evaluation not included in the UFSAR or to methodologies included in the UFSAR that are not used in the safety analyses or to establish design bases may be screened out.

Methods of evaluation that may be identified in references listed at the end of UFSAR sections or chapters are not subject to control under 10 CFR 50.59 unless the UFSAR states they were used for specific analyses within the scope of 10 CFR 50.59(c)(2)(viii).

Changes to methods of evaluation included in the UFSAR are considered adverse and require evaluation under 10 CFR 50.59 if the changes are outside the constraints and limitations associated with use of the method, e.g., identified in a topical report and/or SER. If the changes are within constraints and limitations associated with use of the method, the change is not considered adverse and may be screened out.

Proposed use of an alternative method is considered an adverse change that must be evaluated under 10 CFR 50.59(c)(2)(viii).

The following examples illustrate the screening of changes to methods of evaluation:

Example 1 The UFSAR identifies the name of the computer code used for performing containment performance analyses, with no further discussion of the methods employed within the code for performing those analyses. Changes to the computer code may be screened out provided that the changes are within the constraints and limitations identified in the associated topical report and SER.

A change that goes beyond restrictions on the use of the method would be considered adverse and evaluated under 10 CFR 50.59(c)(2)(viii) to determine 38

NEI 96-07, Revision 1 November 2000 if prior NRC approval is required.

Example 2 The UFSAR describes the methods used for atmospheric heat transfer and containment pressure response calculations contained within the CONTEMPT computer code. The code is also used for developing long-term temperature profiles (post-recirculation phase of LOCA) for environmental qualification through modeling of the residual heat removal system. Neither this application of the code nor the analysis method is discussed in the UFSAR. A revision to CONTEMPT to incorporate more dynamic modeling of the residual heat removal system transfer of heat to the ultimate heat sink would screen out because this application of the code is not described in the UFSAR as being used in the safety analyses or to establish design bases. Changes to CONTEMPT that affect the atmospheric heat transfer or containment pressure predictions may not screen out (because the UFSAR describes this application in the safety analyses), and may require a 10 CFR 50.59 evaluation.

Example 3 The steamline break mass and energy release calculations were originally performed at a power level of 105% of the nominal power (plus uncertainties) in order to allow margin for a future power up-rate. The utility later decided that it would not pursue the power up-rate and wished to use the margin to address other equipment qualification issues. The steamline break mass and energy release calculations were reanalyzed, using the same methodology, at 100%

power (plus uncertainties). This change would screen out as a methodology change because the proposed activity involved a change to an input parameter

(% power) and not a methodology change. This change should be screened per Section 4.2.1.1 to determine if it constitutes a change to the facility as described in the UFSAR that requires evaluation under 10 CFR 50.59(c)(2)(i-vii).

Example 4 The LOCA mass and energy release calculations were originally performed at a power level of 105% of the nominal power, plus uncertainties. Some of the assumptions in the analysis were identified as nonconservative, but the NRC concluded in the associated SER that the overall analysis was conservative because of the use of the higher initial power. The utility later decided that it would not pursue the power up-rate and wished to use the margin to address other equipment qualification issues. The LOCA break mass and energy release calculations were reanalyzed, using the same methodology, at 100%

power (plus uncertainties). This change would not screen out because the 39

NEI 96-07, Revision 1 November 2000 proposed activity involved a change to an input parameter that was integral to the NRC approval of the methodology.

Example 5 Due to fuel management changes, core physics parameters change for a particular reload cycle. The topical report and associated SER that describe how the core physics parameters are to be calculated explicitly allow use of either 2-D or 3-D modeling for the analysis. A change to add or remove discretionary conservatism via use of 3-D methods instead of 2-D methods or vice-versa would screen out because the change is within the terms and conditions of the SER.

4.2.2 Is the Activity a Test or Experiment Not Described in the UFSAR?

As discussed in Section 3.14, tests or experiments not described in the UFSAR are activities where an SSC is utilized or controlled in a manner that is outside the reference bounds of the design for that SSC or inconsistent with analyses or description in the UFSAR.

As discussed in Section 4.1.2, testing associated with maintenance is assessed and managed under 10 CFR 50.65(a)(4) and is not subject to 10 CFR 50.59.

Tests and experiments that are described in the UFSAR may be screened out at this step. Tests and experiments that are not described in the UFSAR may be screened out provided the test or experiment is bounded by tests and experiments that are described. Similarly, tests and experiments not described in the UFSAR may be screened out provided that affected SSCs will be appropriately isolated from the facility.

Examples of tests that would screen in at this step (assuming they were not associated with maintenance or described in the UFSAR) would be:

1. For BWRs, hydrogen injection into the reactor coolant system to minimize stress corrosion cracking

2. For BWRs, zinc injection into the reactor coolant system to reduce activation

3. For PWRs, ECCS flow tests that affect the ability to remove decay heat

4. Operation with fuel demonstration assemblies.

40

NEI 96-07, Revision 1 November 2000 Examples of tests that would screen out would be:

1. Steam generator moisture carryover tests (provided such testing is described in the UFSAR)

2. Balance-of-plant heat balance test

3. Information gathering that is nonintrusive to the operation or design function of the associated SSC.

4.2.3 Screening Documentation 10 CFR 50.59 record-keeping requirements apply to 10 CFR 50.59 evaluations performed for activities that screened in, not to screening records for activities that screened out. However, documentation should be maintained in accordance with plant procedures of screenings that conclude a proposed activity may be screened out (i.e., that a 10 CFR 50.59 evaluation was not required). The basis for the conclusion should be documented to a degree commensurate with the safety significance of the change. For changes, the documentation should include the basis for determining that there would be no adverse effect on design functions, etc. Typically, the screening documentation is retained as part of the change package. This documentation does not constitute the record of changes required by 10 CFR 50.59, and thus is not subject to 10 CFR 50.59 documentation and reporting requirements. Screening records need not be retained for activities for which a 10 CFR 50.59 evaluation was performed or for activities that were never implemented.

4.3 EVALUATION PROCESS Once it has been determined that a given activity requires a 10 CFR 50.59 evaluation, the written evaluation must address the applicable criteria of 10 CFR 50.59(c)(2). These eight criteria are used to evaluate the effects of proposed activities on accidents and malfunctions previously evaluated in the UFSAR and their potential to cause accidents or malfunctions whose effects are not bounded by previous analyses.

Criteria (c)(2)(ivii) are applicable to activities other than changes in methods of evaluation. Criterion (c)(2)(viii) is applicable to changes in methods of evaluation. Each activity must be evaluated against each applicable criterion.

If any of the criteria are met, the licensee must apply for and obtain a license amendment per 10 CFR 50.90 before implementing the activity. The 41

NEI 96-07, Revision 1 November 2000 Example 4 Licensee X has received NRC approval for the use of a method of evaluation at Facility A for performing steamline break mass and energy release calculations for environmental qualification evaluations. The terms and conditions for the use of the method are detailed in the NRC SER. The SER also describes limitations associated with the method. Licensee Y wants to apply the method at its Facility B. Licensee Y has satisfied the guidelines of GL 83-11, Supplement 1. After reviewing the method, approved application, SER and related documentation, to verify that applicable terms, conditions and limitations are met and to ensure the method is applicable to their type of plant, Licensee Y conducts a 10 CFR 50.59 evaluation. Licensee Y concludes that the change is not a departure from a method of evaluation because it has determined the method is appropriate for the intended application, the terms and conditions for its use as specified in the SER have been satisfied, and the method has been approved by the NRC.

Example 5 The NRC has approved the use of computer code and the associated analysis of a steamline break for use in the evaluation of component stresses. A licensee uses the same computer code and analysis methodology to replace its evaluation of the containment temperature response. This change would require prior NRC approval unless the methodology had been previously approved for evaluating containment temperature response.

4.4 APPLYING 10 CFR 50.59 TO COMPENSATORY ACTIONS TO ADDRESS NONCONFORMING OR DEGRADED CONDITIONS Three general courses of action are available to licensees to address non-conforming and degraded conditions. Whether or not 10 CFR 50.59 must be applied, and the focus of a 10 CFR 50.59 evaluation if one is required, depends on the corrective action plan chosen by the licensee, as discussed below:

Q If the licensee intends to restore the SSC back to its as-designed condition then this corrective action should be performed in accordance with 10 CFR 50, Appendix B (i.e., in a timely manner commensurate with safety).

This activity is not subject to 10 CFR 50.59.

Q If an interim compensatory action is taken to address the condition and involves a temporary procedure or facility change, 10 CFR 50.59 should be applied to the temporary change. The intent is to determine whether the temporary change/compensatory action itself (not the degraded condition) impacts other aspects of the facility or procedures described in the 70

NEI 96-07, Revision 1 November 2000 UFSAR. In considering whether a temporary change impacts other aspects of the facility, a licensee should pay particular attention to ancillary aspects of the temporary change that result from actions taken to directly compensate for the degraded condition.

Q If the licensee corrective action is either to accept the condition as-is resulting in something different than its as-designed condition, or to change the facility or procedures, 10 CFR 50.59 should be applied to the corrective action, unless another regulation applies, e.g., 10 CFR 50.55a.

In these cases, the final corrective action becomes the proposed change that would be subject to 10 CFR 50.59.

In resolving degraded or nonconforming conditions, the need to obtain NRC approval for a proposed activity does not affect the licensee's authority to operate the plant. The licensee may make mode changes, restart from outages, etc., provided that necessary SSCs are operable and the degraded condition is not in conflict with the technical specifications or the license.

The following example illustrates the process for implementing a temporary change as a compensatory action to address a degraded/nonconforming condition:

A level transmitter for one Reactor Coolant Pump (RCP) lower oil reservoir failed while at power. The transmitter provides an alarm function, but not an automatic protective action function. The transmitter and associated alarm are described in the UFSAR, as protective features for the RCPs, but no technical specification applies. Loss of the transmitter does not result in the loss of operability for any technical specification equipment. The transmitter fails in a direction resulting in a continuous alarm in the control room. The alarm circuitry provides a common alarm for both the upper and lower oil reservoir circuits, so transmitter failure causes a hanging alarm and a masking of proper operation of the remaining functional transmitter.

Precautionary measures are taken to monitor lower reservoir oil level as outlined in the alarm manual using available alternate means. An interim compensatory action is proposed to lift the leads (temporary change) from the failed transmitter to restore the alarm function for the remaining functioning transmitter.

Lifting the leads is a compensatory action (temporary change) that is subject to 10 CFR 50.59. The 10 CFR 50.59 screening would be applied to the temporary change itself (lifted leads), not the degraded condition (failed transmitter), to determine its impact on other aspects of the facility described in the UFSAR. If screening determines that no other UFSAR-described SSCs would be affected by this compensatory action, the temporary change would screen out, i.e., not require a 10 CFR 50.59 evaluation.

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SCE ATTACHMENT 21 U.S. NUCLEAR REGULATORY COMMISSION November 2000 REGULATORY GUIDE OFFICE OF NUCLEAR REGULATORY RESEARCH REGULATORY GUIDE 1.187 (Draft was issued as DG-1095)

GUIDANCE FOR IMPLEMENTATION OF 10 CFR 50.59, CHANGES, TESTS, AND EXPERIMENTS A. INTRODUCTION In 10 CFR Part 50, Domestic Licensing of Production and Utilization Facilities, Section 50.59, Changes, Tests and Experiments, contains requirements for the process by which licensees may make changes to their facilities and procedures as described in the safety analysis report, without prior NRC approval, under certain conditions. The rule was promulgated in 1962 and revised in 1968.

As a result of lessons learned from operating experience and other initiatives related to control of conformance of facilities with their final safety analysis report (FSAR) descriptions, the NRC determined that additional action was necessary to provide clarity and consistency in implementation of the rule. The staff recommended specific actions in SECY-97-205, Integration and Evaluation of Results from Recent Lessons-Learned Reviews,1 dated September 10, 1997. In a staff requirements memorandum dated March 24, 1998,1 the Commission directed the staff to initiate rulemaking to revise the requirements of 10 CFR 50.59 to clarify the requirements and to allow changes involving only minimal increases in probability or consequences to be made without prior NRC approval.

The proposed rule was published for comment in October 1998. Following consideration of public comments, on October 4, 1999 (64 FR 53582), the NRC issued a final revision to 10 CFR 50.59 that becomes effective 90 days after approval of regulatory guidance, which is 1

Copies are available for inspection or copying for a fee from the NRC Public Document Room at 11555 Rockville MD; the PDRs mailing address is Mail Stop PDR, Washington, DC 20555; telephone (301) 415-4737 or (800)397-4209; fax (301)415-3548; email <PDR@NRC.GOV>.

Regulatory guides are issued to describe and make available to the public such information as methods acceptable to the NRC staff for implementing specific parts of the NRCs regulations, techniques used by the staff in evaluating specific problems or postulated accidents, and data needed by the NRC staff in its review of applications for permits and licenses. Regulatory guides are not substitutes for regulations, and compliance with them is not required. Methods and solutions different from those set out in the guides will be acceptable if they provide a basis for the findings requisite to the issuance or continuance of a permit or license by the Commission.

This guide was issued after consideration of comments received from the public. Comments and suggestions for improvements in these guides are encouraged at all times, and guides will be revised, as appropriate, to accommodate comments and to reflect new information or experience. Written comments may be submitted to the Rules and Directives Branch, ADM, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.

Regulatory guides are issued in ten broad divisions: 1, Power Reactors; 2, Research and Test Reactors; 3, Fuels and Materials Facilities; 4, Environmental and Siting; 5, Materials and Plant Protection; 6, Products; 7, Transportation; 8, Occupational Health; 9, Antitrust and Financial Review; and 10, General.

Single copies of regulatory guides (which may be reproduced) may be obtained free of charge by writing the Distribution Services Section, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by fax to (301)415-2289, or by email to DISTRIBUTION@NRC.GOV. Electronic copies of this guide are available on the internet at NRCs home page at <WWW.NRC.GOV> in the Reference Library under Regulatory Guides. This guide is also in the Electronic Reading Room at NRCs home page, along with other recently issued guides, Accession Number ML003759710.

contained in this Regulatory Guide 1.187. The text of the revised rule is contained in Appendix A to this regulatory guide for convenience.

The information collections contained in this regulatory guide are covered by the requirements of 10 CFR Part 50, which were approved by the Office of Management and Budget, approval number 3150-0011. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

B. DISCUSSION OBJECTIVE The objectives of 10 CFR 50.59 are to ensure that licensees (1) evaluate proposed changes to their facilities for their effects on the licensing basis of the plant, as described in the FSAR, and (2) obtain prior NRC approval for changes that meet specified criteria as having a potential impact upon the basis for issuance of the operating license. This regulatory guide, through its endorsement of a guideline document for licensees, provides guidance on complying with the revised requirements of 10 CFR 50.59.

DEVELOPMENT OF INDUSTRY GUIDELINE, NEI 96-07 Following publication of the revised rule, the Nuclear Energy Institute (NEI) submitted a guidance document for the implementation of 10 CFR 50.59 and requested NRC endorsement through a regulatory guide. Following a series of meetings between NEI and the NRC, a revised version of the guidance document was submitted by NEI on February 22, 2000. The NRC published for public comment a Draft Regulatory Guide, DG-1095, which endorsed, with certain clarifications, Revision 1 of NEI 96-07. As part of their comments in response to the draft guide, NEI proposed revisions to NEI 96-07 to respond to the issues raised by the NRC staff in its draft guide. Subsequently, NEI submitted a revised version of NEI 96-07, dated November 2000, for endorsement.

C. REGULATORY POSITION

1. NEI 96-07 Revision 1 of NEI 96-07, Guidelines for 10 CFR 50.59 Evaluations,2 dated November 2000, provides methods that are acceptable to the NRC staff for complying with the provisions of 10 CFR 50.59.

2 Copies of NEI 96-07 are available through NRCs web site, <WWW.NRC.GOV> through NRCs Electronic Reading Room, under Accession Number ML003771157. Copies are available for inspection or copying for a fee from the NRC Public Document Room at 11555 Rockville Pike, Rockville, MD; the PDRs mailing address is Washington, DC 20555; telephone (301)415-4737 or (800)397-4209; fax (301 415-3548; email <PDR@NRC.GOV>.

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2. OTHER DOCUMENTS REFERENCED IN NEI 96-07 Revision 1 of NEI 96-07 references other documents, but NRCs endorsement of Revision 1 should not be considered an endorsement of the referenced documents.

3. USE OF EXAMPLES IN NEI 96-07 Revision 1 of NEI 96-07 includes examples to supplement the guidance. While appropriate for illustrating and reinforcing the guidance in Revision 1 of NEI 96-07, the NRCs endorsement of Revision 1 should not be considered a determination that the examples are applicable for all licensees. A licensee should ensure that an example is applicable to its particular circumstances before implementing the guidance as described in an example.

4. GUIDANCE FOR FSAR SUPPLEMENTS FOR LICENSE RENEWAL The guidance in Revision 1 of NEI 96-07 and in this regulatory guide is applicable to information added to the FSAR in accordance with 10 CFR 54.21(d), that is, for summary descriptions of the programs and activities for managing the effects of aging and the evaluation of time-limited aging analyses.

5. APPLICABILITY TO NON-POWER REACTORS While most of the examples and specific discussion focus on power reactors, the guidance contained in Revision 1 of NEI 96-07 is also applicable to evaluations performed by licensees for non-power reactors. Certain of the provisions in the guidance that discuss the relationship of other regulatory requirements to 10 CFR 50.59 may not be fully applicable to non-power reactors because of differences in those other requirements. For example, non-power reactors are not subject to 10 CFR 50.65, and thus, the guidance concerning use of risk assessments for temporary alterations associated with maintenance in lieu of 10 CFR 50.59 reviews would not be applicable.

6. APPLICABILITY TO 10 CFR 72.48 EVALUATIONS The guidance contained in Revision 1 of NEI 96-07 is also generally applicable to evaluations performed by licensees of independent spent fuel storage facilities (ISFSIs) or spent fuel storage cask design certificate holders for implementation of the revised 10 CFR 72.48. The NRC plans to issue guidance that would endorse (with comment if needed) a companion industry guidance document that has adjustments to the examples and other specific aspects as they pertain to 10 CFR 72.48.

7. APPLICABILITY OF PAST NRC COMMUNICATIONS The NRC has issued a number of communications such as Generic Letters or Bulletins that discussed or referred to 10 CFR 50.59. In considering whether the information in those documents remains applicable, it should be noted that those documents were based on the rule requirements that existed at the time of issuance. To the extent that the discussion therein relates to specific aspects of the rule, such as evaluation criteria that have been revised, these past documents may no 1.187-3

longer be fully consistent and the new rule requirements would prevail. The status is unchanged of other parts of these documents that are not affected by the revisions to the rule.

8. USE OF OTHER METHODS To meet the requirements of 10 CFR 50.59, licensees may use methods other than those set forth in Revision 1 of NEI 96-07. The NRC will determine the acceptability of other methods on a case-by-case basis.

D. IMPLEMENTATION The purpose of this section is to provide information to licensees and applicants regarding the NRC staffs plans for using this regulatory guide.

Except in those cases in which a licensee proposes an acceptable alternative method for complying with the specified portions of the NRCs regulations, the methods described in this guide will be used in the evaluation of licensee compliance with the requirements of 10 CFR 50.59.

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APPENDIX A TEXT OF 10 CFR 50.59

§ 50.59 Changes, Tests, and Experiments.

(a) Definitions for the purposes of this section:

(1) Change means a modification or addition to, or removal from, the facility or procedures that affects a design function, method of performing or controlling the function, or an evaluation that demonstrates that intended functions will be accomplished.

(2) Departure from a method of evaluation described in the FSAR (as updated) used in establishing the design bases or in the safety analyses means (i) changing any of the elements of the method described in the FSAR (as updated) unless the results of the analysis are conservative or essentially the same; or (ii) changing from a method described in the FSAR to another method unless that method has been approved by NRC for the intended application.

(3) Facility as described in the final safety analysis report (as updated) means:

(i) The structures, systems, and components (SSC) that are described in the final safety analysis report (FSAR) (as updated),

(ii) The design and performance requirements for such SSCs described in the FSAR (as updated), and (iii) The evaluations or methods of evaluation included in the FSAR (as updated) for such SSCs which demonstrate that their intended function(s) will be accomplished.

(4) Final Safety Analysis Report (as updated) means the Final Safety Analysis Report (or Final Hazards Summary Report) submitted in accordance with § 50.34, as amended and supplemented, and as updated per the requirements of § 50.71(e) or § 50.71(f), as applicable.

(5) Procedures as described in the final safety analysis report (as updated) means those procedures that contain information described in the FSAR (as updated) such as how structures, systems, and components are operated and controlled (including assumed operator actions and response times).

(6) Tests or experiments not described in the final safety analysis report (as updated) means any activity where any structure, system, or component is utilized or controlled in a manner which is either:

(i) Outside the reference bounds of the design bases as described in the final safety analysis report (as updated) or (ii) Inconsistent with the analyses or descriptions in the final safety analysis report (as updated).

(b) Applicability. This section applies to each holder of a license authorizing operation of a production or utilization facility, including the holder of a license authorizing operation of a nuclear power reactor that has submitted the certification of permanent cessation of operations required under § 50.82(a)(1) or a reactor licensee whose license has been amended to allow possession but not operation of the facility.

(c)(1) A licensee may make changes in the facility as described in the final safety analysis report (as updated), make changes in the procedures as described in the final safety analysis report (as 1.187-A-1

updated), and conduct tests or experiments not described in the final safety analysis report (as updated) without obtaining a license amendment pursuant to § 50.90 only if:

(i) A change to the technical specifications incorporated in the license is not required, and (ii) The change, test, or experiment does not meet any of the criteria in paragraph (c)(2) of this section.

(2) A licensee shall obtain a license amendment pursuant to § 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would:

(i) Result in more than a minimal increase in the frequency of occurrence of an accident previously evaluated in the final safety analysis report (as updated);

(ii) Result in more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety previously evaluated in the final safety analysis report (as updated);

(iii) Result in more than a minimal increase in the consequences of an accident previously evaluated in the final safety analysis report (as updated);

(iv) Result in more than a minimal increase in the consequences of a malfunction of an SSC important to safety previously evaluated in the final safety analysis report (as updated);

(v) Create a possibility for an accident of a different type than any previously evaluated in the final safety analysis report (as updated);

(vi) Create a possibility for a malfunction of an SSC important to safety with a different result than any previously evaluated in the final safety analysis report (as updated);

(vii)Result in a design basis limit for a fission product barrier as described in the FSAR (as updated) being exceeded or altered; or (viii) Result in a departure from a method of evaluation described in the FSAR (as updated) used in establishing the design bases or in the safety analyses (3) In implementing this paragraph, the FSAR (as updated) is considered to include FSAR changes resulting from evaluations performed pursuant to this section and analyses performed pursuant to § 50.90 since submittal of the last update of the final safety analysis report pursuant to

§ 50.71 of this part.

(4) The provisions in this section do not apply to changes to the facility or procedures when the applicable regulations establish more specific criteria for accomplishing such changes.

(d)(1)The licensee shall maintain records of changes in the facility, of changes in procedures, and of tests and experiments made pursuant to paragraph (c) of this section. These records must include a written evaluation which provides the bases for the determination that the change, test or experiment does not require a license amendment pursuant to paragraph (c)(2) of this section.

(2) The licensee shall submit, as specified in § 50.4, a report containing a brief description of any changes, tests, and experiments, including a summary of the evaluation of each. A report must be submitted at intervals not to exceed 24 months.

(3) The records of changes in the facility must be maintained until the termination of a license issued pursuant to this part or the termination of a license issued pursuant to 10 CFR Part 54, whichever is later. Records of changes in procedures and records of tests and experiments must be maintained for a period of 5 years.

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VALUE/IMPACT STATEMENT A separate Value/Impact Statement was not prepared for this regulatory guide. The Value/Impact Statement that was prepared as part of the Regulatory Analysis for the rulemaking in May 1999 is still applicable. Copies of the Regulatory Analysis are available for inspection or copying for a fee in the NRCs Public Document Room at 11555 Rockville Pike, Rockville, MD, Washington, DC, as part of SECY-99-130, dated May 12, 1999. The PDR may be reached by telephone at (301)415-4737 or fax at (301)415-3548.

ADAMS Accession Number of Regulatory Guide 1.187:

ML003759710 ADAMS Accession Number of Revision 1 of NEI 96-07:

ML003771157

SCE ATTACHMENT 22 Quad Cities Extended Power Uprate (EPU)

Meeting March 22, 2007

Introduction Randy Gideon Quad Cities (QC) Plant Manager 2

AGENDA 9 Introduction 9 Vibration Source Reduction 9 Steam Dryer Replacement 9 Electromatic Relief Valve (ERV) Actuator Modification 9 EPU Commitments 9 EPU Monitoring Plan 9 Summary 3

Introduction 9 Purpose

• Communicate the results and conclusions of the modifications and evaluations performed supporting EPU operation at QC

• Status EPU-related regulatory commitments

• Demonstrate QC can continue to operate safely at EPU power levels 4

Introduction 9 17% power uprate (2511 MWt to 2957 MWt)

• Approved in December 2001

• Initial EPU operation in 2002 9 Following initial EPU operation, both QC units experienced vibration related problems, resulting in several shutdowns and reactor power restrictions 5

Introduction 9 Initial actions focused on improving components ability to withstand EPU loading conditions

• ERV actuators

• Steam dryers 9 In parallel, actions included identifying and eliminating the vibration driving force

• Acoustic side branch (ASB) modification 9 Supporting analysis and evaluations previously reviewed with NRC technical staff

• QC technical issues resolved 6

Introduction 2 02 3 03 04 04 05 05 6 06 n0 ly n0 ly n ly n ly n0 ly Ja Ju Ja Ju Ja Ju Ja Ju Ja Ju ERV ASBs Restricted to Degradation Return to Initial EPU Pre-EPU Installed/ERV Steam Dryer Full-EPU ramp up Power Upgrade Dryer Failure Replaced Power QC1 Both Units Both Units ERV Restricted to Returned to Degradation Pre-EPU Full-EPU Power Power QC2 Initial EPU ASBs Steam Dryer ramp up Installed/ERV Replaced Dryer Failure Upgrade Dryer Failure Dryer Failure Target Rock Restricted to Return to S/RV Pre-EPU Full-EPU setpoint Power Power 7

SCE ATTACHMENT 23 NRC: Power Reactor Status Report for July 1, 2004 Page 1 of 3 Home > Electronic Reading Room > Document Collections > Reports Associated with Events > Power Reactor Status Reports

> 2004 > July 1 Power Reactor Status Report for July 1, 2004 UNEVALUATED INFORMATION PROVIDED BY THE FACILITY On this page:

z Region 1 Reactors z Region 2 Reactors z Region 3 Reactors z Region 4 Reactors Region 1 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Beaver Valley 100 1

Beaver Valley 100 2

Calvert Cliffs 1 100 Calvert Cliffs 2 100 FitzPatrick 100 Ginna 100 Hope Creek 1 100 Indian Point 2 100 Indian Point 3 100 Limerick 1 100 Limerick 2 100 Millstone 2 100 Millstone 3 100 Nine Mile Point 100 1

Nine Mile Point 100 2

Oyster Creek 100 Peach Bottom 100 2

Peach Bottom 100 3

Pilgrim 1 100 Salem 1 90 INCREASING POWER

• Salem 2 100

• Seabrook 1 100 Susquehanna 100 1

Susquehanna 100 2

Three Mile 100 Island 1 Vermont FORCED OUTAGE - ISO PHASE BUS DUCT http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2004/20040701p... 1/8/2013

NRC: Power Reactor Status Report for July 1, 2004 Page 2 of 3 Yankee DISASSEMBLY/REPAIRS AND GENERATOR END 006/18/2004 TESTING IN PROGRESS Region 2 Change in report Number of Scrams Unit Power Down Reason or Comment

(*) (#)

Browns Ferry 003/03/1985DEFUELED 1

Browns Ferry 100 2

Browns Ferry 100 3

Brunswick 1 100 MAXIMUM OPERATING Brunswick 2 96

• POWER Catawba 1 100 Catawba 2 100 Crystal River 3 100 Farley 1 100 Farley 2 100 Harris 1 100 Hatch 1 100 MAXIMUM OPERATING Hatch 2 99 POWER McGuire 1 100 McGuire 2 100 North Anna 1 100 North Anna 2 100 Oconee 1 100 Oconee 2 100 Oconee 3 100 Robinson 2 100 Saint Lucie 1 100 Saint Lucie 2 100 Sequoyah 1 100 Sequoyah 2 100 Summer 100 Surry 1 100 Surry 2 100 Turkey Point 3 100 Turkey Point 4 100 Vogtle 1 100 Vogtle 2 100 Watts Bar 1 100 Region 3 Change in report Number of Scrams Unit PowerDown Reason or Comment

(*) (#)

Braidwood 1 100 Braidwood 2 100 Byron 1 100 Byron 2 100 Clinton 95 100% GENERATOR CAPACITY D.C. Cook 1 100 D.C. Cook 2 100 Davis-Besse 100 Dresden 2 98 100% ELECTRICAL CAPACITY Dresden 3 98 100% ELECTRICAL CAPACITY Duane Arnold 94 100% ELECTRICAL CAPABILITY Fermi 2 100 Kewaunee 100 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2004/20040701p... 1/8/2013

NRC: Power Reactor Status Report for July 1, 2004 Page 3 of 3 La Salle 1 100 La Salle 2 100 Monticello 100 Palisades 100 Perry 1 100 Point Beach 1 100 Point Beach 2 100 Prairie Island 100 1

Prairie Island 100 2

LIMITED IN POWER (STEAM DRYER Quad Cities 1 85 MONITORING)

LIMITED IN POWER (STEAM DRYER Quad Cities 2 85 MONITORING)

Region 4 Reason or Change in report Number of Scrams Unit PowerDown Comment (*) (#)

Arkansas Nuclear 1 100 Arkansas Nuclear 2 100 Callaway 100 Columbia Generating 100

• Station Comanche Peak 1 100 Comanche Peak 2 100 Cooper 100 Diablo Canyon 1 100 Diablo Canyon 2 100 Fort Calhoun 100 Grand Gulf 1 100 Palo Verde 1 100 Palo Verde 2 100 Palo Verde 3 100 River Bend 1 100 San Onofre 2 100 San Onofre 3 100 South Texas 1 100 South Texas 2 100 Waterford 3 100 Wolf Creek 1 100

• - Power Reactor Status Report change within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

1. - Number of reactor scrams or trips within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Notes:

z Reactor status data collected between 4 a.m. and 8 a.m. each day.

z All times are based on eastern time.

Page Last Reviewed/Updated Thursday, March 29, 2012 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2004/20040701p... 1/8/2013

NRC: Power Reactor Status Report for May 1, 2005 Page 1 of 3 Home > Electronic Reading Room > Document Collections > Reports Associated with Events > Power Reactor Status Reports

> 2005 > May 1 Power Reactor Status Report for May 1, 2005 UNEVALUATED INFORMATION PROVIDED BY THE FACILITY On this page:

z Region 1 Reactors z Region 2 Reactors z Region 3 Reactors z Region 4 Reactors Region 1 Change in report Number of Scrams Unit Power Down Reason or Comment

(*) (#)

Beaver Valley 1 100 HOLDING FOR NI Beaver Valley 2 90

• CALIBRATION Calvert Cliffs 1 100 Calvert Cliffs 2 100 FitzPatrick 100 Ginna 100 Hope Creek 1 100 Indian Point 2 100 Indian Point 3 100 Limerick 1 100 Limerick 2 100 Millstone 2 004/08/2005DEFUELED Millstone 3 73 INCREASING POWER

• Nine Mile Point 1 35 TURBINE WARMUP

• Nine Mile Point 2 100 Oyster Creek 100 Peach Bottom 2 100 Peach Bottom 3 100 Pilgrim 1 004/18/2005REFUELING OUTAGE Salem 1 100 Salem 2 004/05/2005REFUELING OUTAGE Seabrook 1 6 INCREASING POWER

• Susquehanna 1 100 Susquehanna 2 73 INCREASING POWER

• Three Mile Island 100 1

Vermont Yankee 100 Region 2 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Browns 003/03/1985DEFUELED Ferry 1 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2005/20050501p... 1/8/2013

NRC: Power Reactor Status Report for May 1, 2005 Page 2 of 3 Browns 100 Ferry 2 Browns 100 Ferry 3 Brunswick 1 100 REDUCED POWER FOR FEED PUMP Brunswick 2 66 MAINTENANCE Catawba 1 100 Catawba 2 100 Crystal REDUCED POWER FOR CONSENSATE PUMP 70

• River 3 AND WATERBOX MAINTENANCE Farley 1 100 Farley 2 68 REDUCED POWER FOR WATERBOX CLEANING

• MANUAL TRIP ON LOSS OF A CONDENSATE Harris 1 005/01/2005

• 1 PUMP - EN#41654 Hatch 1 100 Hatch 2 100 McGuire 1 100 McGuire 2 100 North Anna 100 1

North Anna 100 2

Oconee 1 004/08/2005REFUELING OUTAGE Oconee 2 100 Oconee 3 100 Robinson 2 100 Saint Lucie 100 1

Saint Lucie 100 2

Sequoyah 1 100 Sequoyah 2 004/24/2005REFUELING OUTAGE Summer 004/23/2005REFUELING OUTAGE Surry 1 100 Surry 2 004/23/2005REFUELING OUTAGE Turkey Point 100 3

Turkey Point 004/10/2005DEFUELED 4

Vogtle 1 2 INCREASING POWER

• Vogtle 2 100 Watts Bar 1 100 Region 3 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Braidwood 1 100 Braidwood 2 004/17/2005REFUELING OUTAGE Byron 1 100 Byron 2 100

• Clinton 92 100% ELECTRICAL CAPABILITY

• D.C. Cook 1 100

• D.C. Cook 2 100 Davis-Besse 100 Dresden 2 97 100% ELECTRICAL CAPABILITY Dresden 3 84 INCREASING POWER

• Duane 003/28/2005REFUELING OUTAGE

• Arnold Fermi 2 100 Kewaunee 002/20/2005 SHUTDOWN TO RESOLVE AUXILIARY http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2005/20050501p... 1/8/2013

NRC: Power Reactor Status Report for May 1, 2005 Page 3 of 3 FEEDWATER ISSUE La Salle 1 100 La Salle 2 100 Monticello 100 Palisades 100 Perry 1 002/21/2005REFUELING OUTAGE Point Beach 98 AUX FEED PUMP SURVEILLANCE TESTING

• 1 Point Beach 004/01/2005REFUELING OUTAGE - DEFUELED 2

Prairie Island 100 1

Prairie Island 004/15/2005REFUELING OUTAGE 2

LIMITED IN POWER (STEAM DRYER Quad Cities 1 85 MONITORING)

LIMITED IN POWER (STEAM DRYER Quad Cities 2 85 MONITORING)

Region 4 Change in report Number of Scrams Unit Power Down Reason or Comment

(*) (#)

Arkansas Nuclear 1 100 Arkansas Nuclear 2 100 Callaway 100 Columbia Generating 100 Station Comanche Peak 1 100 Comanche Peak 2 60 INCREASING POWER

• Cooper 100 Diablo Canyon 1 100 Diablo Canyon 2 100 Fort Calhoun 002/26/2005DEFUELED Grand Gulf 1 100 Palo Verde 1 100 REFUELING OUTAGE -

Palo Verde 2 004/01/2005 DEFUELED Palo Verde 3 100 River Bend 1 100 San Onofre 2 100 San Onofre 3 100 South Texas 1 100 South Texas 2 100 Waterford 3 004/16/2005REFUELING OUTAGE Wolf Creek 1 004/08/2005REFUELING OUTAGE

• - Power Reactor Status Report change within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

1. - Number of reactor scrams or trips within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Notes:

z Reactor status data collected between 4 a.m. and 8 a.m. each day.

z All times are based on eastern time.

Page Last Reviewed/Updated Thursday, March 29, 2012 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2005/20050501p... 1/8/2013

SCE ATTACHMENT 24 NRC: Power Reactor Status Report for February 3, 2012 Page 1 of 4 Home > Electronic Reading Room > Document Collections > Reports Associated with Events > Power Reactor Status Reports

> 2012 > February 3 Power Reactor Status Report for February 3, 2012 UNEVALUATED INFORMATION PROVIDED BY THE FACILITY On this page:

z Region 1 Reactors z Region 2 Reactors z Region 3 Reactors z Region 4 Reactors Region 1 Change in Number of Unit PowerDown Reason or Comment report (*) Scrams (#)

Beaver Valley 1 100

• Beaver Valley 2 100

• Calvert Cliffs 1 93 PLANNED PLANT TESTING

• Calvert Cliffs 2 100

• FitzPatrick 100 Ginna 100 Hope Creek 1 100

• Indian Point 2 100 Indian Point 3 100 Limerick 1 100 ALL 6 FEEDWATER HEATERS OOS

• Limerick 2 100

• Millstone 2 100 Millstone 3 100 Nine Mile Point 1 100 Nine Mile Point 2 100 Oyster Creek 100 Peach Bottom 2 100 Peach Bottom 3 100 Pilgrim 1 100 Salem 1 100 Salem 2 100 HOLDING POWER BASED ON GENERATOR Seabrook 1 85

• DELTA T LIMIT Susquehanna 1 99 100% ELECTRICAL CAPABILITY

• Susquehanna 2 99 100% ELECTRICAL CAPABILITY

• Three Mile Island 100

• 1 HOLDING POWER FOR PRE-Vermont Yankee 95

• CONDITIONING Region 2 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Browns 100 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120203p... 1/8/2013

NRC: Power Reactor Status Report for February 3, 2012 Page 2 of 4 Ferry 1 Browns 100 Ferry 2 Browns 100 Ferry 3 Brunswick 1 95 COASTDOWN TO REFUELING OUTAGE INCREASING POWER - INADVERTENT "2A" Brunswick 2 50

• RECIRC PUMP RUNBACK Catawba 1 100 Catawba 2 100 Crystal River DEFUELED - CONTAINMENT TENSIONING 009/25/2009 3 ON HOLD Farley 1 100 Farley 2 100 Harris 1 100 Hatch 1 88 COASTDOWN TO REFUELING OUTAGE Hatch 2 100

• McGuire 1 100 McGuire 2 100 North Anna 100 1

North Anna 100 2

Oconee 1 100 Oconee 2 100 Oconee 3 100 Robinson 2 001/17/2012REFUELING OUTAGE

• Saint Lucie 1 011/27/2011CORE RELOAD IN PROGRESS Saint Lucie 2 100 Sequoyah 1 100 Sequoyah 2 100 Summer 100 Surry 1 100 Surry 2 100 Turkey Point 100 3

Turkey Point 100 4

Vogtle 1 100 Vogtle 2 100 Watts Bar 1 100 Region 3 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Braidwood 1 100 Braidwood 2 100 SLIGHTLY REDUCED TO 99.6% POWER FOR Byron 1 100 FEEDWATER FLOW INSTRUMENT INVESTIGATION Byron 2 001/30/2012FORCED OUTAGE Clinton 97 100% ELECTRICAL GENERATION D.C. Cook 1 100

• D.C. Cook 2 100

• Davis-Besse 100 Dresden 2 100 Dresden 3 100 Duane 100 Arnold Fermi 2 100 Kewaunee 100 La Salle 1 100 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120203p... 1/8/2013

NRC: Power Reactor Status Report for February 3, 2012 Page 3 of 4 La Salle 2 100 Monticello 100 Palisades 100 Perry 1 100 Point Beach 100 1

Point Beach 100 2

Prairie 100 Island 1 Prairie 100 Island 2 Quad Cities 100 1

Quad Cities 100 2

Region 4 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Arkansas Nuclear 100 1

Arkansas Nuclear 100 2

Callaway 100 Columbia Generating 100 Station Comanche Peak 100 1

Comanche Peak 100 2

RECOVERING FROM SINGLE LOOP Cooper 55

• OPERATION - INCREASING POWER STARTING 2/4 - 230KV MORRO BAY-Diablo Canyon 1 100 TEMPLETON LINE OOS FOR MAINTENANCE STARTING 2/4 - 230KV MORRO BAY-Diablo Canyon 2 100 TEMPLETON LINE OOS FOR MAINTENANCE Fort Calhoun 004/09/2011REFUELING OUTAGE POWER LIMITED BASED ON SECOND STAGE Grand Gulf 1 96 MSR ISOLATED Palo Verde 1 100 Palo Verde 2 100 Palo Verde 3 100 River Bend 1 100 REFUELING OUTAGE - DEFUELED -

San Onofre 2 001/09/2012SWITCHYARD RESTRICTIONS DUE TO UNIT 2 DIESEL OUTAGE FORCED OUTAGE - SWITCHYARD San Onofre 3 001/31/2012RESTRICTIONS DUE TO UNIT 2 DIESEL OUTAGE South Texas 1 100 South Texas 2 011/28/2011MAINTENANCE OUTAGE Waterford 3 100 WORK CONTINUING TO RESTORE FROM LOSS Wolf Creek 1 001/13/2012 OF OFFSITE POWER

• - Power Reactor Status Report change within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

1. - Number of reactor scrams or trips within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Notes:

z Reactor status data collected between 4 a.m. and 8 a.m. each day.

http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120203p... 1/8/2013

NRC: Power Reactor Status Report for February 3, 2012 Page 4 of 4 z All times are based on eastern time.

Page Last Reviewed/Updated Friday, March 30, 2012 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120203p... 1/8/2013

NRC: Power Reactor Status Report for September 13, 2012 Page 1 of 3 Home > Electronic Reading Room > Document Collections > Reports Associated with Events > Power Reactor Status Reports

> 2012 > September 13 Power Reactor Status Report for September 13, 2012 UNEVALUATED INFORMATION PROVIDED BY THE FACILITY On this page:

z Region 1 Reactors z Region 2 Reactors z Region 3 Reactors z Region 4 Reactors Region 1 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Beaver Valley 1 100 MINIMUM GENERATION ALERT COASTDOWN TO REFUELING OUTAGE Beaver Valley 2 96

• MINIMUM GENERATION ALERT Calvert Cliffs 1 100 MINIMUM GENERATION ALERT Calvert Cliffs 2 100 MINIMUM GENERATION ALERT FitzPatrick 90 COASTDOWN TO REFUELING OUTAGE

• Ginna 100 Hope Creek 1 100 Indian Point 2 100 138 KV FEEDER RESTRICTIONS Indian Point 3 100 138 KV FEEDER RESTRICTIONS Limerick 1 100 Limerick 2 100 Millstone 2 100

• Millstone 3 100 Nine Mile Point 100 1

Nine Mile Point 100 2

Oyster Creek 100 Peach Bottom 2 009/09/2012REFUELING OUTAGE

• Peach Bottom 3 100 Pilgrim 1 100 Salem 1 100 Salem 2 100 POWER LIMITED TO 85% BASED ON Seabrook 1 85 GENERATOR STATOR COOLING DELTA T LIMIT MINIMUM GENERATION ALERT HIGH SYSTEM Susquehanna 1 100 VOLTAGE ACTION MINIMUM GENERATION ALERT HIGH SYSTEM Susquehanna 2 100 VOLTAGE ACTION Three Mile MINIMUM GENERATION ALERT HIGH SYSTEM 100 Island 1 VOLTAGE ACTION Vermont 100 Yankee http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120913p... 1/8/2013

NRC: Power Reactor Status Report for September 13, 2012 Page 2 of 3 Region 2 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Browns Ferry 100 1

Browns Ferry 100 2

Browns Ferry 100 3

Brunswick 1 100 Brunswick 2 100 Catawba 1 100 Catawba 2 100 Crystal River DEFUELED - CONTAINMENT 009/25/2009 3 TENSIONING ON HOLD Farley 1 100 Farley 2 100 Harris 1 100 Hatch 1 100 Hatch 2 100 McGuire 1 100 McGuire 2 97 COASTDOWN TO REFUELING OUTAGE North Anna 1 100 North Anna 2 100 Oconee 1 100 Oconee 2 100 Oconee 3 100 Robinson 2 100 Saint Lucie 1 100 Saint Lucie 2 008/05/2012DEFUELED Sequoyah 1 100 Sequoyah 2 100 Summer 100 Surry 1 100 Surry 2 100 Turkey Point 30% PWR HOLD FOR SECONDARY 29 3 CHEMISTRY Turkey Point 100 4

Vogtle 1 95 COASTDOWN TO REFUELING OUTAGE Vogtle 2 100 Watts Bar 1 009/10/2012REFUELING OUTAGE Region 3 Change in report Number of Scrams Unit Power Down Reason or Comment

(*) (#)

Braidwood 1 100 Braidwood 2 100 Byron 1 009/10/2012REFUELING OUTAGE

• Byron 2 100 Clinton 97 100% ELECTRICAL CAPABILITY D.C. Cook 1 100 MINIMUM GENERATION ALERT D.C. Cook 2 100 MINIMUM GENERATION ALERT Davis-Besse 100

• Dresden 2 100 Dresden 3 100 COASTDOWN TO REFUELING Duane Arnold 93

• OUTAGE Fermi 2 68 SOUTH FEED PUMP UNAVAILABLE http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120913p... 1/8/2013

NRC: Power Reactor Status Report for September 13, 2012 Page 3 of 3 Kewaunee 100 La Salle 1 100 La Salle 2 100 Monticello 100 Palisades 100 Perry 1 100 Point Beach 1 100 Point Beach 2 100 Prairie Island 100 1

Prairie Island 100 2

Quad Cities 1 100 Quad Cities 2 100 Region 4 Change in Number of Unit Power Down Reason or Comment report (*) Scrams (#)

Arkansas Nuclear 1 100 COASTDOWN TO REFUELING Arkansas Nuclear 2 92 OUTAGE Callaway 100 Columbia Generating 100 Station Comanche Peak 1 100 Comanche Peak 2 100 Cooper 100 Diablo Canyon 1 100 Diablo Canyon 2 100 Fort Calhoun 004/09/2011REFUELING OUTAGE Grand Gulf 1 100 Palo Verde 1 100 Palo Verde 2 100 Palo Verde 3 100 River Bend 1 100 San Onofre 2 001/09/2012REFUELING OUTAGE FORCED OUTAGE - S/G San Onofre 3 001/31/2012 REPAIR South Texas 1 100 South Texas 2 100 Waterford 3 100 Wolf Creek 1 100

• - Power Reactor Status Report change within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

1. - Number of reactor scrams or trips within past 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Notes:

z Reactor status data collected between 4 a.m. and 8 a.m. each day.

z All times are based on eastern time.

Page Last Reviewed/Updated Thursday, October 11, 2012 http://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2012/20120913p... 1/8/2013