April 8, 2005

EA-04-221

Gregg R. Overbeck, Senior Vice 

 President, Nuclear

Arizona Public Service Company

P.O. Box 52034

Phoenix, AZ 85072-2034

SUBJECT: FINAL SIGNIFICANCE DETERMINATION FOR A YELLOW FINDING AND

NOTICE OF VIOLATION - NRC SPECIAL INSPECTION REPORT 2004-014 -

PALO VERDE NUCLEAR GENERATING STATION

Dear Mr. Overbeck:

The NRC’s January 5, 2005, inspection report described the results of a special inspection that

followed up on your discovery in July 2004 that a significant section of containment sump safety

injection piping at all three Palo Verde Nuclear Generating Station (PVNGS) units was void of

water. The report discussed two findings that were being evaluated for further NRC action

under the NRC’s Significance Determination Process or NRC Enforcement Policy. This letter

provides you the results of our evaluation of one of the findings, the preliminary “Greater than

Green” finding involving a failure to maintain portions of the PVNGS emergency core cooling

system (ECCS) filled with water in accordance with design control requirements. This finding

was processed under the NRC’s significance determination process. In separate

correspondence, we are providing you the results of our enforcement deliberations on the

second finding, an apparent violation of 10 CFR 50.59 that was processed under the NRC’s

Enforcement Policy.

NRC’s evaluation of the design control finding considered the fact that Arizona Public Service

Company (APS) discovered this condition at PVNGS in July 2004, following notification from

another facility where a similar problem had been identified. On July 31, 2004, APS reported

this condition to NRC under the provisions of 10 CFR 50.72(b)(3)(v), noting that the voided

section of piping had the potential to prevent the fulfillment of the safety function to remove

residual heat and mitigate the consequences of a loss-of-coolant accident. In early August,

Palo Verde took corrective action to fill the voided piping in all three units, completing those

actions by August 4, 2004.

At your request, a Regulatory and Predecisional Enforcement Conference was held on

February 17, 2005, to discuss APS’s perspectives on the risk significance of the design control

issue. During the meeting the APS staff described their assessment of the significance of the

finding, including the results of detailed pump testing APS sponsored to assess the

performance of the high pressure safety injection (HPSI) and containment spray (CS) pumps

with portions of the ECCS suction piping voided. The APS staff also described corrective

actions, including the root cause evaluations for the failure to maintain the design of ECCS
Arizona Public Service Company -2-

suction piping. The APS staff indicated that maintaining voided ECCS suction piping was

contrary to the original design intent and was an unanalyzed condition. Your investigation

identified possible causes as including: (1) the design requirement was specified, but the end

user did not consider the design requirement and incorporate the requirement into procedures;

(2) the design requirement was recognized, but there was a breakdown in communicating the

design requirement to the end user; and (3) the design requirement was not recognized by the

responsible design organization.

The APS staff indicated that the pump testing demonstrated that high pressure safety injection

pumps would function for all loss of coolant accidents associated with a pipe break greater than

2.0 inches in diameter. Additionally, the APS staff indicated that, as a conservative measure

during the significance determination, no change was made to your probabilistic safety

assessment model to account for small-break loss of coolant accidents between 2.0 and 2.3

inches. The APS staff indicated that the significance of the finding should be characterized as

having low to moderate safety significance (White) because the change in core damage

frequency from the subject performance deficiency was 7.0 x 10-6.

After considering the information developed during the inspection, the information APS provided

at the conference, and the information APS provided in letters dated December 27, 2004,

February 10, 2005, February 15, 2005, February 24, 2005, and February 28, 2005, the NRC

has concluded that the inspection finding is most appropriately characterized as a Yellow

finding, i.e., an issue with substantial importance to safety that will result in additional NRC

inspection and potentially other NRC action. While we agreed with many of the assumptions

that formed the basis for your risk determination, we identified many uncertainties associated

with the conduct of the pump tests. A discussion of these uncertainties, their effect on our

significance determination, and the primary basis for the NRC’s conclusion, follows.

The NRC’s review determined that the pump testing provided useful insights into post-accident

high pressure safety injection pump performance. Nevertheless, there were several

uncertainties associated with the testing and analysis methodologies that could have an impact

on the overall conclusions regarding the availability of ECCS pumps following a loss-of-coolant

accident. The significant test method uncertainties were in the areas of: (1) the use of the

Froude Correlation and scaling, and (2) the impact of temperature on required net positive

suction head. There were also several uncertainties associated with differences between the

test configuration and the actual plant configuration. The significant configuration uncertainties

were in the areas of: (1) the use of ambient temperature water during testing in lieu of postaccident temperature water, (2) the use of a method of air injection during the full scale testing

that did not represent the actual void discovered in the plant, (3) the failure to model the

transition between suction sources and the associated impact on check valve and system

response, and (4) the failure during testing to account for post-accident conditions affecting the

pump discharge.

We evaluated the above test method and test configuration concerns and concluded that they

introduced large qualitative uncertainties associated with the selection of the loss-of-coolant

accident break spectrum utilized by the APS staff in completing the safety analysis. After

accounting for the uncertainties, we concluded that at least some portion of the medium loss-ofcoolant accident break spectrum should be included in the significance determination of the

failure to maintain the ECCS suction piping filled with water.
Arizona Public Service Company -3-

Taking into account these uncertainties, we determined that the most appropriate value for the

change in core damage frequency lies between 5.7 x 10-6, the result assuming that the

performance deficiency only affects system response to small breaks, and 4.6 x 10-5, the result

assuming that high pressure safety injection pumps would fail on recirculation during a mediumbreak LOCA. Given that 89 percent of the range of core damage frequency lies in the Yellow

region, as defined by the significance determination process, we have concluded that the most

appropriate characterization of the significance of this finding is Yellow. Additional details of our

evaluation and basis for arriving at a Yellow significance determination are contained in

Enclosure 2.

We will use the NRC Action Matrix to determine the most appropriate NRC response for this

issue. We will notify you by separate correspondence of that determination.

You have 30 calendar days from the date of this letter to appeal the staff’s determination of

significance for this Yellow finding. Such appeals will be considered to have merit only if they

meet the criteria in NRC Inspection Manual Chapter 0609, Attachment 2.

The NRC also has determined that the failure to maintain portions of the Palo Verde ECCS in

accordance with design specifications is a violation of 10 CFR Part 50, Appendix B, Criterion III,

Design Control. This violation is cited in the enclosed Notice of Violation (Notice), Enclosure 1. 

The circumstances surrounding this violation were described in detail in the subject inspection

report. In accordance with the NRC Enforcement Policy, the Notice of Violation is considered

escalated enforcement action because it is associated with a Yellow finding. You are required

to respond to the violation and should follow the instructions specified in the enclosed Notice in

preparing your response.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosures, and your response will be made available electronically for public inspection in the

NRC Public Document Room or from the NRC’s document system (ADAMS), accessible from

the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your

response should not include any personal privacy, proprietary, or safeguards information so

that it can be made available to the public without redaction. The NRC also includes significant

enforcement actions on its Web site at www.nrc.gov; select What We Do, Enforcement, then

Significant Enforcement Actions.

Sincerely,

/RA/

Bruce S. Mallett

Regional Administrator

Docket Nos. 50-528; 50-529; 50-530

License Nos. NPF-41; NPF-51; NPF-74

Enclosures: see next page
Arizona Public Service Company -4-

1. Notice of Violation

2. Final Significance Determination

cc w/Enclosures 1 & 2:

Steve Olea

Arizona Corporation Commission

1200 W. Washington Street

Phoenix, AZ 85007

Douglas K. Porter, Senior Counsel

Southern California Edison Company

Law Department, Generation Resources

P.O. Box 800

Rosemead, CA 91770

Chairman

Maricopa County Board of Supervisors

301 W. Jefferson, 10th Floor

Phoenix, AZ 85003

Aubrey V. Godwin, Director

Arizona Radiation Regulatory Agency

4814 South 40 Street

Phoenix, AZ 85040

M. Dwayne Carnes, Director

Regulatory Affairs/Nuclear Assurance

Palo Verde Nuclear Generating Station

Mail Station 7636

P.O. Box 52034

Phoenix, AZ 85072-2034

Hector R. Puente

Vice President, Power Generation

El Paso Electric Company

310 E. Palm Lane, Suite 310

Phoenix, AZ 85004

Jeffrey T. Weikert

Assistant General Counsel

El Paso Electric Company

Mail Location 167

123 W. Mills

El Paso, TX 79901

John W. Schumann

Los Angeles Department of Water & Power

Southern California Public Power Authority

P.O. Box 51111, Room 1255-C

Los Angeles, CA 90051-0100

John Taylor

Public Service Company of New Mexico

2401 Aztec NE, MS Z110

Albuquerque, NM 87107-4224

Cheryl Adams

Southern California Edison Company

5000 Pacific Coast Hwy. Bldg. DIN

San Clemente, CA 92672

Robert Henry

Salt River Project

6504 East Thomas Road

Scottsdale, AZ 85251

Brian Almon

Public Utility Commission

William B. Travis Building

P.O. Box 13326

1701 North Congress Avenue

Austin, TX 78701-3326
Enclosure 1

NOTICE OF VIOLATION

Arizona Public Service Company Docket Nos. 50-528; 50-529; 50-530

Palo Verde Nuclear Generating Station License Nos. NPF-41; NPF-51; NPF-74

EA-04-221

During an NRC inspection completed December 8, 2004, a violation of NRC requirements was

identified. In accordance with the "General Statement of Policy and Procedure for NRC 

Enforcement Actions," NUREG-1600, the violation is listed below:

10 CFR Part 50, Appendix B, Criterion III, Design Control states, in part, that measures

shall be established to assure that the design basis is correctly translated into

specifications, procedures, and instructions. 

The design basis for the Palo Verde Nuclear Generating Station (PVNGS) is specified,

in part, in the plant Updated Final Safety Analysis Report (UFSAR). Section 6.3 of the

UFSAR, "Emergency Core Cooling System," states, in part, that the safety injection

piping will be maintained filled with water, and that during recirculation mode, the

available net positive suction head for the containment spray and high pressure safety

injection pumps is 25.8 feet and 28.8 feet, respectively (values that assume the pump

suction piping is filled with water.)

Contrary to the above, from initial plant licensing until July 2004, the design control

measures established by the licensee were not adequate to assure that the design basis

for the PVNGS emergency core cooling system (ECCS) was appropriately translated

into specifications, procedures, and instructions. The licensee had no specifications,

procedures or instructions in place to assure that the design basis for the ECCS system

was maintained. Specifically, except for limited periods of time following ECCS leak

testing prior to 1992, the licensee failed to maintain portions of the containment sump

safety injection recirculation piping filled with water in accordance with the UFSAR, a

nonconformance that affected the available net positive suction head for the

containment spray and high pressure safety injection pumps as described in the

UFSAR. This condition existed at Units 1, 2 and 3 of the PVNGS facility from initial

plant operation (1985, 1986 and 1987, respectively) until August 2004, at which time

corrective actions were taken to fill the affected piping.

This violation is associated with a Yellow SDP finding.

Pursuant to the provisions of 10 CFR 2.201, Arizona Public Service Company is hereby

required to submit a written statement or explanation to the U.S. Nuclear Regulatory

Commission, ATTN: Document Control Desk, Washington, DC 20555 with a copy to the

Regional Administrator, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, TX, 76011, and

a copy to the NRC Resident Inspector at the Palo Verde facility, within 30 days of the date of

the letter transmitting this Notice of Violation (Notice). This reply should be clearly marked as a

"Reply to a Notice of Violation; EA-04-221" and should include for each violation: (1) the

reason for the violation, or, if contested, the basis for disputing the violation or severity level, (2)

the corrective steps that have been taken and the results achieved, (3) the corrective steps that

will be taken to avoid further violations, and (4) the date when full compliance will be achieved. 
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Your response may reference or include previous docketed correspondence, if the

correspondence adequately addresses the required response. If an adequate reply is not

received within the time specified in this Notice, an order or a Demand for Information may be

issued as to why the license should not be modified, suspended, or revoked, or why such other

action as may be proper should not be taken. Where good cause is shown, consideration will

be given to extending the response time. 

If you contest this enforcement action, you should also provide a copy of your response, with

the basis for your denial, to the Director, Office of Enforcement, U.S. Nuclear Regulatory

Commission, One White Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738.

Because your response will be made available electronically for public inspection in the NRC

Public Document Room or from the NRC's document system (ADAMS), accessible from the

NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should

not include any personal privacy, proprietary, or safeguards information so that it can be made

available to the public without redaction. If personal privacy or proprietary information is

necessary to provide an acceptable response, then please provide a bracketed copy of your

response that identifies the information that should be protected and a redacted copy of your

response that deletes such information. If you request withholding of such material, you must

specifically identify the portions of your response that you seek to have withheld and provide in

detail the bases for your claim of withholding (e.g., explain why the disclosure of information will

create an unwarranted invasion of personal privacy or provide the information required by 10

CFR 2.390(b) to support a request for withholding confidential commercial or financial

information). If safeguards information is necessary to provide an acceptable response, please

provide the level of protection described in 10 CFR 73.21. 

Dated this 8th day of April 2005
Enclosure 2

Final Significance Determination

Palo Verde Nuclear Generating Station

Voiding in the Recirculation Sump Suction Line

The NRC reviewed each of the differences between the licensee’s evaluation documented in

their analysis, Document Number 13-NS-C074, “Significance Determination of Containment

Sump Air Entrainment,” and presented during the Regulatory Conference held on

February 17, 2005, and the NRC’s preliminary significance determination. Using the additional

data provided by the licensee, as well as evaluations and input from the NRC staff, a final

significance determination was performed by modifying the preliminary evaluation as

appropriate. The documentation that follows is not a stand-alone evaluation; the reader must

also be familiar with the preliminary significance determination documented in NRC Special

Inspection Report 05000528/2004014, 05000529/2004014, AND 05000530/2004014,

Attachment D, “Phase 2 and Phase 3 Risk Assessments.”

I. Internal Events:

Table 1 presents the differences between the licensee’s evaluation and the NRC’s

preliminary evaluation for the internal initiators affected by the performance deficiency.

TABLE 1

Differences

Internal Events Assessment

Initiating Event NRC Preliminary

∆CDF

PVNGS

∆CDF

Large LOCA 1.44 x 10-6 0

Medium LOCA 1.06 x 10-5 0

Small LOCA 9.15 x 10-7 4.5 x 10-6

Transients (PSV) 2.89 x 10-6 2.7 x 10-7

LOOP (RCP seal

LOCA)

9.72 x 10-8 0

Total 1.59 x 10-5 4.8 x 10-6

The NRC evaluated each of these differences, to determine the appropriate

assumptions to use for the final determination. The following characterizes each of the

changes made to the NRC’s preliminary significance determination:
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2. Recovery

Based on the testing performed, the licensee assumed that the containment

spray pumps would not fail beyond nominal failure probabilities and that high

pressure safety injection (HPSI) pumps would only fail during small-break lossof-coolant accidents (LOCAs). In addition, because the failures were limited to

only the most severe conditions on the pumps, the licensee assumed that the

pumps would not be recoverable.

The NRC adjusted the preliminary analysis to indicate that only the HPSI pumps

would fail and that this failure would damage the pumps such that they could not

be recovered in the short term. Making these assumptions, the NRC used the

Standardized Plant Analysis Risk Model for Palo Verde 1, 2, & 3 (SPAR),

Revision 3.03 to quantify the change in core damage frequency (∆CDF) related

to small breaks. The change in assumptions resulted in an increase in ∆CDF to

3.41 x 10-6.

3. Relief Valves

The licensee’s probabilistic risk assessment model indicates that the pressurizer

safety valves would not open if the auxiliary feedwater function is successful, and

that they would always open if the auxiliary feedwater function is not successful.

The NRC agreed that the probability of a safety valve opening was dependent on

the success or failure of auxiliary feedwater. Therefore, the NRC adjusted the

SPAR output to indicate that the safety valves would always open during

transients and special initiators if auxiliary feedwater was unavailable. However,

the NRC did not agree that safety valves could never open given a success of

the auxiliary feedwater function, but concurred that the value used in the SPAR

was too high because the Palo Verde units do not have pilot-operated relief

valves. Therefore, there are no actuation circuits that could inadvertently open

the valves below setpoint and the safety valve setpoints at Palo Verde are

significantly higher than the anticipatory pilot-operated relief valve setpoints at

other plants modeled.

Therefore, the NRC used a screening value of 2.0 x 10-3 as the probability the

safety valves open during a transient with successful auxiliary feedwater

injection. This value was selected because it was an order of magnitude smaller

than the nominal value used in the SPAR. Additionally, the NRC used the same

assumptions used for the small-break LOCAs, namely, the containment spray

pumps would not fail from the air in the suction lines and the HPSI pumps would

fail upon recirculation and would not be recoverable.

The resulting ∆CDF related to transients and special initiators decreased to 

2.33 x 10-8.
-3-

4. Reactor Coolant Pump Seals

The licensee assumes that there is no possibility of a seal LOCA with their

pumps, regardless of seal survival. The manufacturer of the seals has stated

that the seal package clearances are small enough that a total failure of all seals

would only result in a leak of 17 gallons per minute per pump. Therefore, there

could never be a loss-of-coolant accident caused solely by the failure of the

pump seals. The NRC determined that the total impact of this finding on loss of

offsite power sequences were the result of seal LOCAs. As such, the finding

had no impact on loss of offsite power initiators. Therefore, the NRC

determined that the best estimate of ∆CDF was zero.

5. Containment Spray Pumps

The licensee assumed that the containment spray pumps would not fail at a

greater rate as a result of the performance deficiency. They stated that their

testing program proved that the containment spray pumps would continue to

function throughout all accidents.

The staff determined that there were a significant number of concerns related to

the applicability of the licensee’s testing to the actual conditions that the pumps

would be exposed to during an event. However, the NRC determined that most

of these concerns would have a greater impact on the HPSI pumps. Therefore,

the NRC assumed that the licensee’s assumption was correct. This is a best

estimate assumption based on a qualitative estimate of all inputs and data

available. The resulting change was quantified with the changes discussed

under Item 5.

6. HPSI Pumps

The licensee assumed that the HPSI pumps would function throughout all

medium- and large-break scenarios. The licensee stated that their testing

program proved that the finding would not prevent pump success for larger sized

breaks because of the increased containment overpressure and the increase in

flow rates through the pump. Therefore, the licensee concluded that there would

be no increase in the core damage frequency for these accidents.

The staff concurred that the licensee’s testing showed that as break size

increased, the probability of failing the HPSI pumps decreased. Therefore, the

NRC concluded that the licensee’s assumption that the risk from large-break

LOCAs was not affected by this finding was appropriate. The NRC determined

that the best estimate of ∆CDF for large-break sequences was zero.

However, the staff had concerns with the scaling and applicability of the testing

to indicate the ability of the HPSI pumps to perform their function in the plant. 

These concerns are documented in Section III of this document. Therefore, the

NRC determined that the finding could result in a failure of the high pressure

recirculation (HPR) function during a medium-break LOCA. As such, the NRC
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reviewed the range of potential changes in core damage frequency based on

different assumptions. The value of ∆CDF, provided that the HPR function

would never fail as a result of air in the sump lines during a medium-break

LOCA, is zero. If air in the sump lines would have caused the pumps to fail

throughout the entire range of medium-break sizes, the resulting ∆CDF would be

4.03 x 10-5 for medium-break sequences.

The concerns believed by the staff to have the most impact on how well the

testing modeled actual plant conditions are documented in Section III, “Modeling

and Scaling Concerns.”

II. External Events

Table 2 presents the differences between the licensee’s evaluation and the NRC’s

preliminary evaluation for the external initiators affected by the performance deficiency.

TABLE 2

Differences

External Initiators Assessment

Initiating Event NRC Preliminary

∆CDF

PVNGS

∆CDF

Seismic 7.90 x 10-6 3.5 x 10-7

Internal Floods 2.44 x 10-9 1.0 x 10-8

Internal Fire 9.26 x 10-7 1.8 x 10-6

Total External 8.83 x 10-6 2.4 x 10-6

The NRC evaluated each of these differences, to determine the appropriate

assumptions to use for the final determination. The following characterizes each of the

changes made to the NRC’s preliminary significance determination:

A. Cooldown Following Seismic Event

The major difference in the seismic analyses is that NRC did not give credit for

cooldown following a seismic event as a success for a seismically induced smallbreak LOCA, as did the licensee. This was assumed because the atmospheric

dump valves are not required safe shutdown equipment. Also, many additional

activities would compete with the cooldown for operator attention given a

catastrophic earthquake. The earthquake used by the NRC and the licensee

was a seismic event three times larger than the design-basis earthquake. This
-5-

event was given a likelihood, F(3-Seismic), of 3.0 x 10-5/yr in the Palo Verde

Individual Plant Examination of External Events (IPEEE). 

The NRC evaluated the licensee’s assumptions. The IPEEE standard gave a

deterministic requirement to review seismic events to ensure success paths

following a seismically induced small-break LOCA. However, the licensee’s

seismic hazards evaluation determined that this event was unlikely. Therefore,

the NRC used a screening value of 0.1 to model the likelihood that a seismic

event would result in a small-break LOCA, P(SeismicLOCA). Additionally, the NRC

reviewed the sequences for a seismically-induced loss-of-coolant accident. Most

of these sequences involved an extended period between event initiation and the

receipt of a recirculation actuation signal. As such, the NRC determined that

some credit should be given for operators cooling down the plant and placing it in

shutdown cooling prior to the need for recirculation. Therefore, the NRC used a

screening value of 0.1 for the basic event probability that operators failed to

initiate a cooldown in time.

The conditional core damage probability, CCDP(SBLOOP), for a seismically-induced

small-break LOCA with consequential loss of offsite power while the

performance deficiency existed was quantified by the SPAR as 1.454 x 10-1. 

This value was dominated by the 10-percent probability that operators would not

cool down the plant in a timely manner. The baseline conditional core damage

probability, CCDP(Base), for a seismically-induced small-break LOCA with

consequential loss of offsite power was quantified by the SPAR as 2.764 x 10-2. 

The resulting ∆CDF was calculated as follows:

∆CDF = F(3-Seismic) * P(SeismicLOCA) * CCDP(SBLOOP) - F(3-Seismic) * P(SeismicLOCA) * CCDP(Base)

= 3.0 x 10-5/yr * 0.1 * 1.454 x 10-1 - 3.0 x 10-5/yr * 0.1 * 2.764 x 10-2

= 3.53 x 10-7/yr * 1 year = 3.53 x 10-7

This represented a significant decrease in ∆CDF related to seismic initiators

from the value presented in the preliminary significance determination.

B. Quantification of Internal Flooding

For internal floods, Palo Verde used their probabilistic risk assessment model

loss of condenser vacuum and loss of nuclear cooling water event trees to

quantify the change from internal risk. The NRC’s preliminary estimate suggests

that internal floods would pose no more risk than the internal events model.

The NRC adjusted the preliminary determination values to include the revised

internal events assumptions and values from the SPAR. The resulting ∆CDF for

internal flooding was increased to 7.90 x 10-9. This value was very close to the

licensee’s quantification, and the exact value was not important to the final

decision.
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C. Quantification of Internal Fire

The NRC’s preliminary and the licensee’s fire analyses are essentially the same

(less than a factor of two apart). Once the assumption changes in internal

events were applied, the NRC’s value was approximately 3 times higher than the

licensee’s determination. However, Palo Verde has a complete fire model in

their probabilistic risk assessment. Therefore, the NRC determined that the best

estimate would be the licensee’s fully developed result of 1.80 x 10-6.

III. Modeling and Scaling Concerns

The following issues were identified by the staff as the major concerns related to the

modeling and scaling of the licensee’s testing program. Each of these examples has

the potential to affect the licensee’s assumption that the finding does not impact the

HPR function for reactor coolant system break sizes in the medium-break range.

4. Froude Correlation:

The use of Froude numbers as the dimensionless parameter for scaling the test

model was questioned. Actual test results indicated that the Froude number was

not the best scaling factor for the vertical downcomer. The licensee changed the

scaling of this pipe as a result. The staff questioned the use of the Froude

number to model the section of piping from the downcomer to the bifurcation

heading to the HPSI pump suction. If the ratio of the bubble rise rate to actual

pipe velocity was not properly characterized, the result could be a significantly

higher air ingestion rate for the HPSI pumps.

The staff reviewed additional information provided by the licensee on

February 15, 2005, in response to questions raised at the regulatory conference. 

One example of issues identified during this review was that the licensee

provided a document used to justify their use of Froude number scaling in

modeling large pipes (United States Department of the Interior - Engineering

Monograph No. 41, "Air-Water Flow in Hydraulic Structures"). This document

raised the following additional problems or concerns:

• For closed pipe, especially with partial fill and elevation changes, the

report used a different Froude number equation than in the Palo Verde

model.

• In discussing partially filled closed systems it stated, "There are many

literature references that indicate model predictions often underestimate

in the quantity of air which actually flows in prototype structures."

• The document stated, "studies clearly indicate that for estimating airflow

rates using models, it is necessary to accurately reproduce the entire

airflow passage above the water" (meaning not averaging values). The

calculations for this were extremely complex "summation" equations with

the Froude number being just one of many variables.
-7-

• The document stated, ".... conditions can exist whereby bubbles will

move downstream and form into pockets that move against the flow in an

upstream direction. Studies investigated prototype cases in which large

air pockets moved against the flow with sufficient velocity to completely

destroy reinforced concrete." This indicated to the NRC staff that a water

hammer analysis was necessary.

• Finally, the document described complex variations in the air-water flow

regimes based on the flow devices (valves, gates, etc.) and the timing of

these devices. The staff was concerned that the valve types, initial

conditions, and timing of the model could have a major impact on the

results.

2. Modeling of Pump Discharge

The licensee’s full-scale model did not have a check valve nor did it model the

continuous back pressure that would be provided by the reactor coolant system. 

As a result, the staff assumed that the test was much more applicable to steady

state conditions and did not model the likelihood that air ingestion would cause

intermittent closure of the discharge check valve and increase the likelihood that

the pump would air bind.

3. Transition Between Suction Sources

The licensee did not model the switch over from the refueling water tank to the

containment sump during the scale model testing. Additionally, the licensee did

not provide a complete assessment of the differences that may ensue between

the test configuration and that of the plant from the switch over dynamics. The

staff is concerned that the timing of various valve actions would have perturbed

the behavior of gas and water movement and may have introduced an

unrecognized error in the assessment.

4. Air Injection Near Pump Suction

The licensee’s full-scale test involved injecting air into an established steady flow

close to the pump inlet. The staff believes that this model would not have the

same effect on the net positive suction head available as it would if the air were

distributed in the entire flow. Also the established steady flow and flow

momentum would help to sweep air through the pump.

The presence of a high void fraction in the vertical section of the suction pipe

would decrease the net positive suction head available while significantly

increasing net positive suction head required. Inadequate net positive suction

head can cause pump cavitation, pump vibration, and even pump failure. In the

mockup test, big fluctuations in flow and pressure were observed. The

fluctuations could have been magnified by the presence of a large amount of air

in the entire suction flow region.
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5. Containment Environment/Temperature Concerns

The simulated containment pressure used by the licensee in the full-scale

mockup was not the same as the full range of containment pressures under

LOCA conditions. Also, the containment pressure for the mockup was not

consistent with the sump water temperature. The use of 4.2 psig containment

pressure was not consistent with the 70-degree temperature fluid that was used

in the test. Based on accident analysis, a 4.2-psig containment pressure would

correlate to a much higher sump water temperature. Use of 70 degrees F water

while maintaining containment pressure at 4.2 psig is nonconservative with

respect to pump performance.

IV. Sensitivities

The NRC evaluated the sensitivity of the preliminary significance determination results to each

of the assumptions that differed from the licensee’s evaluation assumptions. For each of the

assumptions documented in Sections I and II above, the NRC modified the preliminary results

to reflect the licensee’s assumption. The result, using the NRC’s original quantification

techniques and tools, was sufficiently close to the licensee’s evaluation result that it indicated

that all important assumption differences were represented. The adjusted preliminary

significance determination result, provided in Table 3, was derived using the original

calculational techniques while making changes that resulted in the assumptions listed below. 

Those assumptions that were accepted as the NRC’s best estimate assumptions are indicated

as “best estimate.” Those assumptions where significant uncertainties existed related to the

licensee’s evaluation are marked as “uncertain.” The “uncertain” assumptions were used in the

adjustment solely to provide a baseline for evaluation of the sensitivity of each assumption.

< The containment spray and low-pressure safety injection pump performance was

not affected by the subject finding (uncertain).

< The HPSI pumps were only affected during small-break LOCA sequences

(uncertain).

< Upon failure, the HPSI pumps will not be recoverable because only the worst

impact sequences are being evaluated (best estimate).

< Primary safeties will always lift upon loss of the auxiliary feedwater function, but

will never lift if auxiliary feedwater is successful (best estimate).

< A loss of cooling to the reactor coolant pump seals can never cause a loss-ofcoolant accident (best estimate).

< Ten percent of seismic events of a magnitude larger than 3 times the design

basis will result in a small-break LOCA (best estimate, bounding).

< Operators will fail to cooldown the reactor prior to recirculation 10 percent of the

time following a seismically-induced LOCA (best estimate, bounding).
-9-

< The result from the licensee’s fire PRA is the best available estimate of change

in core damage frequency related to the finding related to internal fires (best

estimate).

The NRC challenged each of these assumptions by restoring the value associated with

the assumption to that used in the preliminary significance determination. The resulting

∆CDF for all initiators following the change in each specific assumption is presented in

Table 3.

TABLE 3

Sensitivities

Critical Assumptions Evaluated

Assumption Change Evaluated Result

(∆CDF)

Adjusted Preliminary

Significance

N/A* 6.7 x 10-6

HPR Always Affected CCF set to 1.0 for MBLOCA 4.7 x 10-5

CSR Fails with HPR CSR Set to 1.0 1.7 x 10-5

Primary Safeties Fail at Nominal Open in 2% of all Transients 1.6 x 10-5

Primary Safeties Fail with AFW Always Open on Loss of AFW 5.7 x 10-6

RCP Seal LOCA LOCA occurs on SBO 1.9 x 10-5

HPR Affected During LBLOCA CCF set to 1.0 for all LOCAs 4.7 x 10-5

Recovery HPR Recovered 76% of time 1.6 x 10-6

Cooldown following Seismic No Cooldown 9.3 x 10-6

* NOTE: The NRC’s adjustment included the differences stated above and

assumptions considered to have a high degree of uncertainty, and should not be

misinterpreted as a best estimate evaluation.
-10-

Abbreviations Used in Table 3:

< HPR: High Pressure Recirculation

< N/A: Not Applicable

< CCF: Common Cause Failure

< CSR: Containment Spray Recirculation

< AFW: Auxiliary Feedwater

< RCP: Reactor Coolant Pump

< LOCA: Loss-of-Coolant Accident

< SBO: Station Blackout

< LBLOCA: Large-Break LOCA

The NRC reviewed the results from the sensitivity study. None of the results indicated

that the significance of the subject finding should be classified below WHITE. While

several of the assumption changes indicated that the significance of the finding would

best be characterized as YELLOW, all but one assumption resulted in a significance

result that was at or near the WHITE/YELLOW boundary.

The only assumption that had an appreciable change (greater than a factor of 2 - 3) in

the significance was whether the performance of the HPSI pumps would be impacted

during a medium-break LOCA. 

V. Final Significance Determination

The NRC made changes to the preliminary analysis for all assumption differences

documented in Sections I and II, that the staff agreed were appropriate to use in a best

estimate evaluation. While several assumptions were questioned by the staff, the NRC

determined that most assumptions did not affect the final significance regardless of the

assumption used. Therefore, the NRC reevaluated the significance of the subject

finding by revising the preliminary significance determination using the licensee’s

assumptions. The result of these adjustments is reflected in Table 4, Column 3.

The NRC then determined by reviewing the sensitivities documented in Table 3, that the

only assumption that could impact the final significance determination was the licensee’s

assumption that the finding would not affect medium-break LOCA sequences. The NRC

revised the evaluation documented in Table 4, Column 3 by assuming that the entire

spectrum of medium-break LOCAs would be affected by the performance deficiency. 

Specifically, the NRC assumed that the HPR function would fail during LOCAs falling

anywhere within the entire spectrum of small and medium breaks. The result of this

adjustment is reflected in Table 4, Column 4.
-11-

TABLE 4

Range of Final Significant Determination

Internal Events Assessment

Column 1

Initiating

Event

Column 2

Preliminary

∆CDF

Column 3

Adjusted

No MBLOCA

Failures

∆CDF

Column 4

Adjusted

w/ MBLOCA

Failures

∆CDF

Large LOCA 1.44 x 10-6 0 0

Medium LOCA 1.06 x 10-5 0 4.03 x 10-5

Small LOCA 9.15 x 10-7 3.41 x 10-6 3.41 x 10-6

Transients (PSV) 2.89 x 10-6 2.33 x 10-8 2.33 x 10-8

LOOP

(RCP seal LOCA)

9.72 x 10-8 0 0

Seismic 7.90 x 10-6 4.36 x 10-7 4.36 x 10-7

Internal Floods 2.44 x 10-9 7.90 x 10-9 7.90 x 10-9

Internal Fire 9.26 x 10-7 1.80 x 10-6 1.80 x 10-6

Total 2.47 x 10-5 5.68 x 10-6 4.60 x 10-5

Given these evaluations, the NRC determined that the best estimate value for the

change in core damage frequency lies somewhere between the 5.7 x 10-6, the result

using the licensee’s assumptions, and 4.6 x 10-5, the result using those assumptions

determined to be the best available information by the NRC and the preliminary

significance determination assumption that HPSI pumps would fail on recirculation

during a medium-break LOCA. The NRC noted that, given this uncertainty range,

approximately 89 percent of the total range lies in the Yellow region defined by the

significance determination process.

Based on the uncertainties associated with the phenomena involved, and the nonconservatisms and other issues associated with the testing documented in Section III,

the staff could not conclude, with reasonable assurance, that there was a high likelihood

that one or both HPSI pumps would have performed its risk-significant function during

the postulated scenarios. The NRC noted that the probability of having a medium-break

LOCA within the spectrum of breaks decreases greatly with the size of the break. This

indicates that the majority of the initiating event frequency is the probability of having a

medium-break LOCA that is on the low end of the break-size spectrum. Therefore,
-12-

relatively small errors in the licensee’s method of determining the maximum break size

that would fail the HPR function could have a large effect on the final result of the risk

determination.

The NRC calculated that an increase in the common cause failure rate of the HPR

function, caused by the subject performance deficiency, of between 8 and 14%

(depending on the model used) throughout the spectrum of medium breaks, would

represent the White/Yellow threshold. Based on the NRC’s determination that the

pumps would be impacted by air intrusion and would not survive during these scenarios,

the NRC determined that the subject performance deficiency is more appropriately

characterized as Yellow, a finding of substantial safety significance.
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