NLS2015026, Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests: Difference between revisions

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| issue date = 03/19/2015
| issue date = 03/19/2015
| title = Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests
| title = Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests
| author name = Limpias O A
| author name = Limpias O
| author affiliation = Nebraska Public Power District (NPPD)
| author affiliation = Nebraska Public Power District (NPPD)
| addressee name =  
| addressee name =  
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=Text=
=Text=
{{#Wiki_filter:N Nebraska Public Power District Always there when you need us 10 CFR 50.55a NLS2015026 March 19, 2015 U.S. Nuclear Regulatory Commission Attention:
{{#Wiki_filter:N Nebraska Public Power District Always there when you need us 10 CFR 50.55a NLS2015026 March 19, 2015 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001
Document Control Desk Washington, D.C. 20555-0001


==Subject:==
==Subject:==
Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests Cooper Nuclear Station, Docket No. 50-298, License No. DPR-46  
Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests Cooper Nuclear Station, Docket No. 50-298, License No. DPR-46


==Dear Sir or Madam:==
==Dear Sir or Madam:==
The purpose of this letter is for the Nebraska Public Power District (NPPD) to request that the Nuclear Regulatory Commission grant relief from certain Inservice Testing (IST) code requirements for the Cooper Nuclear Station (CNS) pursuant to 10 CFR 50.55a. The attached relief requests pertain to the American Society of Mechanical Engineers (ASME) Code for Operation and Maintenance (OM) of Nuclear Power Plants pump and valve testing requirements needed for the fifth ten-year IST interval, which commences on
 
The purpose of this letter is for the Nebraska Public Power District (NPPD) to request that the Nuclear Regulatory Commission grant relief from certain Inservice Testing (IST) code requirements for the Cooper Nuclear Station (CNS) pursuant to 10 CFR 50.55a. The attached relief requests pertain to the American Society of Mechanical Engineers (ASME) Code for Operation and Maintenance (OM) of Nuclear Power Plants pump and valve testing requirements needed for the fifth ten-year IST interval, which commences on March 1, 2016. The applicable code for the fifth ten-year interval is the ASME OM Code 2004 Edition through the 2006 Addenda. NPPD requests approval of these relief requests by March 1, 2016, in support of the start of the fifth ten-year IST interval.
This update is for pumps, valves and snubbers. Relief requests previously approved for the fourth ten-year interval have been updated and are being resubmitted,
Although the permanently installed instrument loops do not meet the accuracy requirements of ASME OM Code ISTB Table ISTB-3510-1 when looking at nameplate accuracies, the effects of these small inaccuracies are insignificant when compared to the measured values, and credit will be taken for the ability to calibrate the loop within the code-allowed tolerance.
Although the permanently installed instrument loops do not meet the accuracy requirements of ASME OM Code ISTB Table ISTB-3510-1 when looking at nameplate accuracies, the effects of these small inaccuracies are insignificant when compared to the measured values, and credit will be taken for the ability to calibrate the loop within the code-allowed tolerance.
NLS2015026 Attachment 2 Page 17 of 99 Relief Request RP-05 Loop Accuracy Requirements (Continued)
 
Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval, this relief request will remain valid as long as the calibrated loop accuracies meet the code required tolerances of < 2.00% of full scale.Using the provisions of this relief request as an alternative to the specific requirements of ISTB Table 3510-1, identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-05 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
NLS2015026 Page 17 of 99 Relief Request RP-05 Loop Accuracy Requirements (Continued)
NLS2015026 Attachment 2 Page 18 of 99 Relief Request RP-06 Reactor Equipment Cooling Pump Flow Rate Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval, this relief request will remain valid as long as the calibrated loop accuracies meet the code required tolerances of < 2.00% of full scale.
Alternative Provides Acceptable Level of Quality and Safety 1. ASME Code Component(s)
Using the provisions of this relief request as an alternative to the specific requirements of ISTB Table 3510-1, identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.
Affected REC-P-A Reactor Equipment Cooling (REC) Pump A REC-P-B Reactor Equipment Cooling Pump B REC-P-C Reactor Equipment Cooling Pump C REC-P-D Reactor Equipment Cooling Pump D 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda 3. Applicable Code Requirement ISTB-3510(b)(1)  
Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.
-The full-scale range of each analog instrument shall not be greater than three times the reference value.4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB-3510(b)(1).
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
The proposed alternative would provide an acceptable level of quality and safety.The installed flow rate instrument range of the reactor equipment cooling pumps is 0 to 4000 gpm. The reference values for flow rate during inservice testing are 1100 gpm. As a result, the instrument range exceeds the requirement of ISTB-35 1 0(b)(1).5. Proposed Alternative and Basis for Use The permanent plant flow Instruments REC-FI-450A and REC-FI-450B are calibrated such that their accuracy is 1.25% of full scale. This yields a total inaccuracy of 50 gpm (0.0125 X 4000 gpm). Reference flow rates for the reactor equipment cooling pumps are 1100 gpm. Based on ISTB-3510(b)(1) this would require, as a maximum, a gauge with a range of 0 to 3300 gpm (3 X 1100 gpm) to bound the lowest reference value for flow.Applying the accuracy requirement of +/- 2% for the pump test, the resulting inaccuracies due to flow would be + 66 gpm (0.02 X 3300 gpm).
: 7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-05 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
NLS2015026 Attachment 2 Page 19 of 99 Relief Request RP-06 Reactor Equipment Cooling Pump Flow Rate Range Requirements (Continued)
 
As an alternative, for the reactor equipment cooling pump inservice tests, CNS will use the installed flow rate instrumentation (0 to 4000 gpm) calibrated to less than +/- 2% such that the inaccuracies due to flow will be less than or equal to that required by the code (+/- 66 gpm). This will ensure that the installed flow rate instrumentation is equivalent to the code, or better, in terms of measuring flow rate.Although the permanently installed flow gauges are above the maximum range limits of ASME OM Code ISTB-35 1 0(b)(1), they are within the accuracy requirements and are, therefore, suitable for the test. Reference NUREG 1482, Revision 2, Section 5.5.1.Using the provisions of this relief request as an alternative to the specific requirements of ISTB-351 0(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-06 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
NLS2015026 Page 18 of 99 Relief Request RP-06 Reactor Equipment Cooling Pump Flow Rate Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
NLS2015026 Attachment 2 Page 20 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
Alternative Provides Acceptable Level of Quality and Safety
Alternative Provides Acceptable Level of Quality and Safety 1. ASME Code Component(s)
: 1.     ASME Code Component(s) Affected REC-P-A         Reactor Equipment   Cooling (REC) Pump A REC-P-B         Reactor Equipment   Cooling Pump B REC-P-C         Reactor Equipment   Cooling Pump C REC-P-D         Reactor Equipment   Cooling Pump D
Affected CS-P-B Core Spray Pump B 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda 3. Applicable Code Requirement ISTB Table ISTB-5121-1, "Centrifugal Pump Test Acceptance Criteria" 4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB Table ISTB-5121-1 during the biennial comprehensive pump test or any other time vibrations are taken to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.). The proposed alternative would provide an acceptable level of quality and safety.The IST Program has consistently required (prior to obtaining relief per RP-06 of the third interval program) that CS Pump B (CS-P-B) be tested on an increased frequency due to vibration values at Points 1 H and 5H, as shown in Figure 1, periodically being in the alert range. Relief is requested from ISTB Table ISTB-5121-1 requirements to test the pump on an increased periodicity due to vibration levels for Points 1H and/or 5H exceeding the ISTB alert range absolute limit for the comprehensive pump test. This request is based on analysis of vibration and pump differential pressure data indicating that no pump degradation is taking place. CNS is proposing to use alternative vibration alert range limits for vibration Points 1 H and 5H. This provides an alternative method that continues to meet the intended function of monitoring the pump for degradation over time while keeping the required action level unchanged.
: 2.     Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
: 3.     Applicable Code Requirement ISTB-3510(b)(1) - The full-scale range of each analog instrument shall not be greater than three times the reference value.
: 4.     Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB-3510(b)(1). The proposed alternative would provide an acceptable level of quality and safety.
The installed flow rate instrument range of the reactor equipment cooling pumps is 0 to 4000 gpm. The reference values for flow rate during inservice testing are 1100 gpm. As a result, the instrument range exceeds the requirement of ISTB-35 10(b)(1).
: 5. Proposed Alternative and Basis for Use The permanent plant flow Instruments REC-FI-450A and REC-FI-450B are calibrated such that their accuracy is 1.25% of full scale. This yields a total inaccuracy of 50 gpm (0.0125 X 4000 gpm). Reference flow rates for the reactor equipment cooling pumps are 1100 gpm. Based on ISTB-3510(b)(1) this would require, as a maximum, a gauge with a range of 0 to 3300 gpm (3 X 1100 gpm) to bound the lowest reference value for flow.
Applying the accuracy requirement of +/- 2% for the pump test, the resulting inaccuracies due to flow would be + 66 gpm (0.02 X 3300 gpm).
 
NLS2015026 Page 19 of 99 Relief Request RP-06 Reactor Equipment Cooling Pump Flow Rate Range Requirements (Continued)
As an alternative, for the reactor equipment cooling pump inservice tests, CNS will use the installed flow rate instrumentation (0 to 4000 gpm) calibrated to less than +/- 2% such that the inaccuracies due to flow will be less than or equal to that required by the code (+/- 66 gpm). This will ensure that the installed flow rate instrumentation is equivalent to the code, or better, in terms of measuring flow rate.
Although the permanently installed flow gauges are above the maximum range limits of ASME OM Code ISTB-35 10(b)(1), they are within the accuracy requirements and are, therefore, suitable for the test. Reference NUREG 1482, Revision 2, Section 5.5.1.
Using the provisions of this relief request as an alternative to the specific requirements of ISTB-351 0(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.
Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
: 7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-06 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
 
NLS2015026 Page 20 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
Alternative Provides Acceptable Level of Quality and Safety
: 1.     ASME Code Component(s) Affected CS-P-B Core Spray Pump B
: 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
: 3. Applicable Code Requirement ISTB Table ISTB-5121-1, "Centrifugal Pump Test Acceptance Criteria"
: 4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB Table ISTB-5121-1 during the biennial comprehensive pump test or any other time vibrations are taken to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.). The proposed alternative would provide an acceptable level of quality and safety.
The IST Program has consistently required (prior to obtaining relief per RP-06 of the third interval program) that CS Pump B (CS-P-B) be tested on an increased frequency due to vibration values at Points 1H and 5H, as shown in Figure 1, periodically being in the alert range. Relief is requested from ISTB Table ISTB-5121-1 requirements to test the pump on an increased periodicity due to vibration levels for Points 1H and/or 5H exceeding the ISTB alert range absolute limit for the comprehensive pump test. This request is based on analysis of vibration and pump differential pressure data indicating that no pump degradation is taking place. CNS is proposing to use alternative vibration alert range limits for vibration Points 1H and 5H. This provides an alternative method that continues to meet the intended function of monitoring the pump for degradation over time while keeping the required action level unchanged.
: 5. Proposed Alternative and Basis for Use Pump Testing Methodology CS-P-B at CNS is tested using a full flow recirculation test line back to the suppression pool each quarter. CS-P-B has a minimum flow line which is used only to protect the pump from overheating when pumping against a closed discharge valve. The minimum flow line isolation valve for CS-P-B is initially open when the pump is started, and flow is initially recirculated through the minimum flow line back to the suppression pool.
: 5. Proposed Alternative and Basis for Use Pump Testing Methodology CS-P-B at CNS is tested using a full flow recirculation test line back to the suppression pool each quarter. CS-P-B has a minimum flow line which is used only to protect the pump from overheating when pumping against a closed discharge valve. The minimum flow line isolation valve for CS-P-B is initially open when the pump is started, and flow is initially recirculated through the minimum flow line back to the suppression pool.
NLS2015026 Attachment 2 Page 21 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
 
Then, the full-flow test line isolation valve is throttled open to establish flow through the full-flow recirculation test line. The minimum flow line is then isolated automatically, and all flow remains through the full-flow test line for the IST test.The B train of the CS system is operated in the same manner and under the same conditions for each test of CS-P-B, regardless of whether CNS is operating or shut down. Consequently, the pump will experience the same potential for flow-induced, low frequency vibration whenever it is tested, whether CNS is operating or shut down. As a result, this relief is requested for the comprehensive pump testing of CS-P-B when vibration measurements are required or any other time vibrations are recorded to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.).CNS considers full-flow testing to be preferable to minimum flow testing due to the ability to evaluate overall pump performance at post-accident flow design conditions.
NLS2015026 Page 21 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Minimum flow testing would provide only limited information about the pump.Nuclear Regulatory Commission (NRC) Staff Document NUREG/CP-0 152 NRC Staff document NUREG/CP-0 152, entitled "Proceedings of the Fourth NRC/ASME Symposium on Valve and Pump Testing," dated July 15-18, 1996, included a paper entitled Nuclear Power Plant Safety Related Pump Issues, by Joseph Colaccino of the NRC staff. That paper presented four key components that should be addressed in a relief request of this type to streamline the review process. These four key components are as follows: I. The licensee should have sufficient vibration history from inservice testing which verifies that the pump has operated at this vibration level for a significant amount of time, with any "spikes" in the data justified.
Then, the full-flow test line isolation valve is throttled open to establish flow through the full-flow recirculation test line. The minimum flow line is then isolated automatically, and all flow remains through the full-flow test line for the IST test.
II. The licensee should have consulted with the pump manufacturer or vibration expert about the level of vibration the pump is experiencing to determine if pump operation is acceptable.
The B train of the CS system is operated in the same manner and under the same conditions for each test of CS-P-B, regardless of whether CNS is operating or shut down. Consequently, the pump will experience the same potential for flow-induced, low frequency vibration whenever it is tested, whether CNS is operating or shut down. As a result, this relief is requested for the comprehensive pump testing of CS-P-B when vibration measurements are required or any other time vibrations are recorded to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.).
III. The licensee should describe attempts to lower the vibration below the defined code absolute levels through modifications to the pump.IV. The licensee should perform a spectral analysis of the pump-driver system to identify all contributors to the vibration levels.The following is a discussion of how these four key components are addressed for this relief request.
CNS considers full-flow testing to be preferable to minimum flow testing due to the ability to evaluate overall pump performance at post-accident flow design conditions. Minimum flow testing would provide only limited information about the pump.
NLS2015026 Attachment 2 Page 22 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Nuclear Regulatory Commission (NRC) Staff Document NUREG/CP-0 152 NRC Staff document NUREG/CP-0 152, entitled "Proceedings of the Fourth NRC/ASME Symposium on Valve and Pump Testing," dated July 15-18, 1996, included a paper entitled Nuclear Power Plant Safety Related Pump Issues, by Joseph Colaccino of the NRC staff. That paper presented four key components that should be addressed in a relief request of this type to streamline the review process. These four key components are as follows:
I. Vibration History (Key Component No. 1)A. Testing Methods and Code Requirements Inconsistent higher vibrations on CS-P-B have been a condition that has existed since original installation of this pump in 1973. During the construction and preoperational testing, vibrations were measured in "mils" at the top and side of the motor outboard (farthest from the pump), the side of the motor inboard (nearest the pump), and pump inboard (nearest the motor). The vibration signals were tape recorded along with the dynamic pressure pulsations in the suction and discharge of the pump as the flow was varied. The intention was to see if hydraulic disturbances were responsible for the observed phenomena.
I.       The licensee should have sufficient vibration history from inservice testing which verifies that the pump has operated at this vibration level for a significant amount of time, with any "spikes" in the data justified.
Observation of the vibration signals on the oscilloscope showed conclusively that the motor was vibrating with randomly distributed bursts of energy at the natural frequency of the total system. Therefore, it was determined that the hydraulic disturbances found in the piping was the source of the energy. Pipe restraints were added that reduced the piping system vibrations.
II.     The licensee should have consulted with the pump manufacturer or vibration expert about the level of vibration the pump is experiencing to determine if pump operation is acceptable.
The monitoring of multiple vibration points over the years had not been a requirement of Section XI of the ASME Code until the adoption of the OM Standards/Codes.
III. The licensee should describe attempts to lower the vibration below the defined code absolute levels through modifications to the pump.
Therefore, at CNS, the first and second ten-year interval IST code requirements did not include the monitoring of multiple vibration points. The CNS second interval IST Program was committed to the 1980 Edition, Winter 1981 Addenda of Section XI. Paragraph IWP-4510 of this code required that "at least one displacement vibration amplitude shall be read during each inservice test." This code was in effect at CNS until the start of the third ten-year interval, which began on March 1, 1996. The CNS third interval IST Program was committed to the 1989 Edition of Section XI, which required multiple vibration points to be recorded during IST pump testing in accordance with the ANSI/ASME Operations and Maintenance Standard, Part 6, 1987 Edition with the 1988 Addenda.However, CNS proactively began monitoring vibration on pumps in the IST Program in velocity units (inches per second) at multiple vibration points in 1990 in accordance with an approved relief request. Therefore, data exists for vibration Points 1 H and 5H from April 1990 to the present. This data is included in the figures provided in this relief request. In April 1990, an analog velocity meter was utilized to begin measuring five different points in units of velocity.
IV.     The licensee should perform a spectral analysis of the pump-driver system to identify all contributors to the vibration levels.
These are the same points measured today. Further technological advances resulted in the utilization of more reliable vibration meters beginning in late 1996. For the fourth interval, which began on March 1, 2006, the 2001 Edition through 2003 Addenda of the ASME OM Code was the code of record.Vibration measurements were required to be taken only during the comprehensive test since the CS-P-B pump is considered a Group B pump. The same will be true for the fifth interval, beginning on March 1, 2016, in which the 2004 Edition through the 2006 Addenda of the ASME OM Code will be the code of record.
The following is a discussion of how these four key components are addressed for this relief request.
NLS2015026 Attachment 2 Page 23 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
 
B. Review of Vibration History Data Beginning in April 1990, five vibration points (IV, 1H, 2H, 3H, 5H) were recorded for CS-P-B. However, the pump was tested at 4720 gpm from April 1990 to April 1992, then at 4800 gpm from April 1992 through December 1994, and finally at 5000 gpm from January 1995 to the present. The January 1995 test was also a post-maintenance test following the work that replaced the restricting orifice in the test return line. The last re-baseline occurred on November 6, 1996, due to the implementation of a new vibration meter with new instrument settings.
NLS2015026 Page 22 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Therefore, it would be appropriate to review the data from this date forward to track for degradation.
I. Vibration History (Key Component No. 1)
This would be over eighteen years of data at the same reference points.CS-P-B IST vibration trend graphs for vibration points 5H, IV, 2H, and 3H (Figures 3a, 4a, 5a, and 6a in this relief request), which include data from November 6, 1996, to the present, show flat or slightly downward trends. Vibration point 1 H shows an essentially flat trend from -2002 to the present (Figure 2a) and when including the data since 1990 (Figure 2b). These observations indicate that CS-P-B vibrations are not increasing in magnitude.
A. Testing Methods and Code Requirements Inconsistent higher vibrations on CS-P-B have been a condition that has existed since original installation of this pump in 1973. During the construction and preoperational testing, vibrations were measured in "mils" at the top and side of the motor outboard (farthest from the pump), the side of the motor inboard (nearest the pump), and pump inboard (nearest the motor). The vibration signals were tape recorded along with the dynamic pressure pulsations in the suction and discharge of the pump as the flow was varied. The intention was to see if hydraulic disturbances were responsible for the observed phenomena. Observation of the vibration signals on the oscilloscope showed conclusively that the motor was vibrating with randomly distributed bursts of energy at the natural frequency of the total system. Therefore, it was determined that the hydraulic disturbances found in the piping was the source of the energy. Pipe restraints were added that reduced the piping system vibrations.
These trends also show that Points 1 H and 5H occasionally exceed the alert range criteria (Figures 2a and 3a). Figure 12 illustrates the trend for CS-P-B differential pressure (D/P) readings from January 1995 (re-baselined pump at 5000 gpm) to the present. This represents approximately twenty years of data for pump D/P with the testing at 5000 gpm. As can be seen from Figure 12, no degradation in pump D/P has occurred.Trend Graphs 2b, 3b, 4b, 5b, and 6b illustrate vibration data dating back to April 1990 for all vibration points. The data prior to 1996 represents data taken with analog, less reliable vibration instruments and, as discussed previously, at differing flows. However, it does clearly indicate that the piping-induced vibrations for vibration Points 1 H and 5H were present in the early 1990s. This condition was also documented in the 1980s. In July 1985, CNS work item #85-2497 documented high vibration readings on the horizontal motor position.
The monitoring of multiple vibration points over the years had not been a requirement of Section XI of the ASME Code until the adoption of the OM Standards/Codes. Therefore, at CNS, the first and second ten-year interval IST code requirements did not include the monitoring of multiple vibration points. The CNS second interval IST Program was committed to the 1980 Edition, Winter 1981 Addenda of Section XI. Paragraph IWP-4510 of this code required that "at least one displacement vibration amplitude shall be read during each inservice test." This code was in effect at CNS until the start of the third ten-year interval, which began on March 1, 1996. The CNS third interval IST Program was committed to the 1989 Edition of Section XI, which required multiple vibration points to be recorded during IST pump testing in accordance with the ANSI/ASME Operations and Maintenance Standard, Part 6, 1987 Edition with the 1988 Addenda.
A pipe resonance problem was suspected at that time.Vibrational readings varied between 0.3 and 0.5 in/sec with spikes to 0.7 in/sec every few seconds. This 1985 documentation, available vibration data since 1990, along with the testing performed during the preoperational time period, substantiates that the piping-induced vibrations have been in existence since the pump was installed.
However, CNS proactively began monitoring vibration on pumps in the IST Program in velocity units (inches per second) at multiple vibration points in 1990 in accordance with an approved relief request. Therefore, data exists for vibration Points 1H and 5H from April 1990 to the present. This data is included in the figures provided in this relief request. In April 1990, an analog velocity meter was utilized to begin measuring five different points in units of velocity. These are the same points measured today. Further technological advances resulted in the utilization of more reliable vibration meters beginning in late 1996. For the fourth interval, which began on March 1, 2006, the 2001 Edition through 2003 Addenda of the ASME OM Code was the code of record.
These graphs indicate that the vibration point trends since April 1990 are essentially flat or slightly downward.
Vibration measurements were required to be taken only during the comprehensive test since the CS-P-B pump is considered a Group B pump. The same will be true for the fifth interval, beginning on March 1, 2016, in which the 2004 Edition through the 2006 Addenda of the ASME OM Code will be the code of record.
Therefore, based on the available data at CNS, this pump has experienced essentially no degradation in vibration levels for -24.5 years or in D/P for -20 years.
 
NLS2015026 Attachment 2 Page 24 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
NLS2015026 Page 23 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
C. Review of "Spikes" in Vibration Data In reviewing the trend data for vibration points 1 H (Figures 2a and 2b) and 5H (Figures 3a and 3b), which includes the code-required frequency ranges (one-third pump running speed to 1000 Hertz [Hz].), random spikes were observed throughout the data that resulted in values above the alert range. These spikes are best described in a 2001 report by Machinery Solutions, Inc., an industry expert on vibrations, as follows: Most of the vibration that is measured on the motor casing is due to excitation of the structural resonances of the motor/pump by turbulent flow. These structural resonances are poorly damped and can be easily excited. Most vertical pumps have similar types of behavior, and it is not necessarily problematic by itself. A problem occurs when a pump has a continuous forcing function whose frequency coincides with a resonance (i.e., running speed). The forcing function in this case is flow turbulence caused in large part by the S-curve in the piping just off the pump discharge.
B. Review of Vibration History Data Beginning in April 1990, five vibration points (IV, 1H, 2H, 3H, 5H) were recorded for CS-P-B. However, the pump was tested at 4720 gpm from April 1990 to April 1992, then at 4800 gpm from April 1992 through December 1994, and finally at 5000 gpm from January 1995 to the present. The January 1995 test was also a post-maintenance test following the work that replaced the restricting orifice in the test return line. The last re-baseline occurred on November 6, 1996, due to the implementation of a new vibration meter with new instrument settings. Therefore, it would be appropriate to review the data from this date forward to track for degradation. This would be over eighteen years of data at the same reference points.
The flow through this area generates lateral broadband forces, due to elbow effects, that excite the resonances in a non-continuous fashion.This is why the amplitude swings so dramatically on the motor case (the location of vibration points 1H and 5H). The system goes from brief periods of excitation to brief periods of no excitation.
CS-P-B IST vibration trend graphs for vibration points 5H, IV, 2H, and 3H (Figures 3a, 4a, 5a, and 6a in this relief request), which include data from November 6, 1996, to the present, show flat or slightly downward trends. Vibration point 1H shows an essentially flat trend from -2002 to the present (Figure 2a) and when including the data since 1990 (Figure 2b). These observations indicate that CS-P-B vibrations are not increasing in magnitude. These trends also show that Points 1H and 5H occasionally exceed the alert range criteria (Figures 2a and 3a). Figure 12 illustrates the trend for CS-P-B differential pressure (D/P) readings from January 1995 (re-baselined pump at 5000 gpm) to the present. This represents approximately twenty years of data for pump D/P with the testing at 5000 gpm. As can be seen from Figure 12, no degradation in pump D/P has occurred.
The discharge riser is also moving side to side from the same forces. Although the discharge piping configuration is both non-standard and less than optimum for this application, it poses no threat to the long-term reliability of either the pump or the motor. The only negative impact is on vibration levels relative to a generic standard.As illustrated previously, there have been no degrading trends associated with vibration data points 1H and 5H for -24.5 years (Figures 2b and 3b). Since June 2002, filtered data (removal of one-third pump running speed to one-half pump running speed frequencies) has been recorded in addition to the current code-required values for vibration points 1H and 5H (reference Figures 2c and 3c for data since 2010). In reviewing this data, the trends are lower in value, steady, and without the spikes that the code-required data contains.
Trend Graphs 2b, 3b, 4b, 5b, and 6b illustrate vibration data dating back to April 1990 for all vibration points. The data prior to 1996 represents data taken with analog, less reliable vibration instruments and, as discussed previously, at differing flows. However, it does clearly indicate that the piping-induced vibrations for vibration Points 1H and 5H were present in the early 1990s. This condition was also documented in the 1980s. In July 1985, CNS work item #85-2497 documented high vibration readings on the horizontal motor position. A pipe resonance problem was suspected at that time.
This further supports the fact that the spikes in the original code data are due to the piping-induced, non-detrimental vibration occurring at the one-third to one-half pump running speed.
Vibrational readings varied between 0.3 and 0.5 in/sec with spikes to 0.7 in/sec every few seconds. This 1985 documentation, available vibration data since 1990, along with the testing performed during the preoperational time period, substantiates that the piping-induced vibrations have been in existence since the pump was installed. These graphs indicate that the vibration point trends since April 1990 are essentially flat or slightly downward. Therefore, based on the available data at CNS, this pump has experienced essentially no degradation in vibration levels for -24.5 years or in D/P for -20 years.
NLS2015026 Attachment 2 Page 25 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
 
II. Consultation  
NLS2015026 Page 24 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
-Pump Manufacturer/Vibration Expert (Key Component No. 2)A. Pump Manufacturer Evaluation of CS-P-B Vibrations Byron Jackson is the pump manufacturer for CS-P-B. The pump is an 8 x 14 x 30 DVSS, vertical mount, single stage centrifugal pump. The pump impeller is mounted on the pump motor's extended shaft. As outlined in the Core Spray System Summary of Preoperational Test, the data obtained for the B Core Spray Pump indicated high vibration.
C. Review of "Spikes" in Vibration Data In reviewing the trend data for vibration points 1H (Figures 2a and 2b) and 5H (Figures 3a and 3b), which includes the code-required frequency ranges (one-third pump running speed to 1000 Hertz [Hz].), random spikes were observed throughout the data that resulted in values above the alert range. These spikes are best described in a 2001 report by Machinery Solutions, Inc., an industry expert on vibrations, as follows:
The high vibration had been recognized early in the construction testing phase, and Byron Jackson sent a representative to the site to investigate.
Most of the vibration that is measured on the motor casing is due to excitation of the structural resonances of the motor/pump by turbulent flow. These structural resonances are poorly damped and can be easily excited. Most vertical pumps have similar types of behavior, and it is not necessarily problematic by itself. A problem occurs when a pump has a continuous forcing function whose frequency coincides with a resonance (i.e., running speed). The forcing function in this case is flow turbulence caused in large part by the S-curve in the piping just off the pump discharge. The flow through this area generates lateral broadband forces, due to elbow effects, that excite the resonances in a non-continuous fashion.
In a letter dated February 16, 1973, the Byron Jackson representative indicated the following:
This is why the amplitude swings so dramatically on the motor case (the location of vibration points 1H and 5H). The system goes from brief periods of excitation to brief periods of no excitation.
: 1. Tests indicated that the natural frequency of the pump was 940 revolutions per minute (rpm) (approximately one-half pump speed) in the direction of the piping and 720 rpm (between one-third and one-half of pump speed) in the direction perpendicular to the piping.2. Observation of the test signals on the oscilloscope showed very conclusively that the motor was vibrating with randomly distributed bursts of energy, the frequency of which matched the natural frequency of the total system. This can only mean that the energy is coming from the hydraulic disturbances found in the piping.3. Whenever large flows are carried in piping, there is usually considerable turbulence associated with the elbows, tees, etc., of the piping configuration, all of which results in piping reactions and motion. Apparently, the vibrating piping was, in turn, vibrating the pump.4. When jacks were installed between the top of the pump and the bottom of the motor flange in an effort to stiffen the motor pump system, the motor vibrations went up due to more energy being transmitted from the pipe-pump system into the motor.5. Testing was performed to determine any weaknesses in the pump-motor mechanical system. The vibration amplitude using the IRD instrument, with the filter set at operating speed, sampled many points vertically along the pump-motor structure.
The discharge riser is also moving side to side from the same forces. Although the discharge piping configuration is both non-standard and less than optimum for this application, it poses no threat to the long-term reliability of either the pump or the motor. The only negative impact is on vibration levels relative to a generic standard.
Plots of the data (along with phase angle determined by means of the strobe light) showed very clearly that the total structure was vibrating as a rigid assembly from the floor mounting.
As illustrated previously, there have been no degrading trends associated with vibration data points 1H and 5H for -24.5 years (Figures 2b and 3b). Since June 2002, filtered data (removal of one-third pump running speed to one-half pump running speed frequencies) has been recorded in addition to the current code-required values for vibration points 1H and 5H (reference Figures 2c and 3c for data since 2010). In reviewing this data, the trends are lower in value, steady, and without the spikes that the code-required data contains. This further supports the fact that the spikes in the original code data are due to the piping-induced, non-detrimental vibration occurring at the one-third to one-half pump running speed.
Examination of the high amplitude vibration signals showed them to be at the extremely low system natural frequencies as determined earlier.6. Such low acceleration levels, along with the system acting as a rigid structure (between motor and pump), means that the motor and pump can operate NLS2015026 Attachment 2 Page 26 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) with these levels of vibration with absolutely no impairment of operating life.This is the picture that seems very clearly described by the data obtained during these tests. There is absolutely no reason to restrict the operation of these pumps in any way.Although the vibration was found to be acceptable, CNS took actions to install new pipe supports as an attempt to reduce these piping-induced vibrations.
 
This action was successful as will be discussed in a later section of this relief request.B. CNS Expert Analysis of CS-P-B Vibrations As the Vibration Monitoring Program expanded in the early 1990s, it became evident that the low frequency, piping-induced vibrations still remained in CS-P-B. Design Change (DC) 94-046 resulted in the replacement of the orifices in the test return line. A March 16, 1995, memo to the CNS IST Engineer from the CNS Lead Civil/Structural Engineer discussed the CS-P-B vibration measurements obtained during DC 94-046 acceptance testing.The vibration data was collected using peak velocity measuring instrumentation as required for the performance of the IST test and with instrumentation that provides displacement and velocity versus frequency data. It was observed that the significant vibrations in the 1 H direction were occurring around 700 cycles per minute (cpm), while the pump speed is at 1780 cpm (i.e., rpm). Given the piping movement of the system, and the knowledge that piping vibrations can commonly occur in the 700 cpm (12 Hz)range, CNS concluded that the pump vibrations were piping dependent.
NLS2015026 Page 25 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
The CNS Lead Civil/Structural Engineer concluded that the significant pump vibrations are occurring at less than one-half of the pump operating speed. The pumps are rigidly mounted at their bases, and any impeller-induced vibrations would occur at the pump running speed or at the vane passing frequency.
II. Consultation - Pump Manufacturer/Vibration Expert (Key Component No. 2)
Therefore, the sub-synchronous pump vibrations are clearly piping induced, non-detrimental to pump/motor service or reliability, and should not be used as a basis for pump degradation.
A. Pump Manufacturer Evaluation of CS-P-B Vibrations Byron Jackson is the pump manufacturer for CS-P-B. The pump is an 8 x 14 x 30 DVSS, vertical mount, single stage centrifugal pump. The pump impeller is mounted on the pump motor's extended shaft. As outlined in the Core Spray System Summary of Preoperational Test, the data obtained for the B Core Spray Pump indicated high vibration. The high vibration had been recognized early in the construction testing phase, and Byron Jackson sent a representative to the site to investigate. In a letter dated February 16, 1973, the Byron Jackson representative indicated the following:
This is because the purpose of pump in-service testing is to diagnose and trend internal pump degradation.
: 1.       Tests indicated that the natural frequency of the pump was 940 revolutions per minute (rpm) (approximately one-half pump speed) in the direction of the piping and 720 rpm (between one-third and one-half of pump speed) in the direction perpendicular to the piping.
The memo further states that the vibration data collection requirement specified in the IST procedure consists of peak velocity recordings, which may be masked by piping-induced vibrations, negating internal pump degradation diagnosis and trending.
: 2.       Observation of the test signals on the oscilloscope showed very conclusively that the motor was vibrating with randomly distributed bursts of energy, the frequency of which matched the natural frequency of the total system. This can only mean that the energy is coming from the hydraulic disturbances found in the piping.
Based on the historical trending data for both CS pumps, the vibration has remained at a consistent amplitude, trending neither upward nor downward, indicating that the induced vibrations are not impairing pump operability, nor capable of preventing the pump from fulfilling its safety function.
: 3.       Whenever large flows are carried in piping, there is usually considerable turbulence associated with the elbows, tees, etc., of the piping configuration, all of which results in piping reactions and motion. Apparently, the vibrating piping was, in turn, vibrating the pump.
The piping vibration is present when flow is present through the test return line. It was visually observed during DC 94-046 acceptance testing that piping vibrations were minimal when flow was directed through the minimum flow line.
: 4.       When jacks were installed between the top of the pump and the bottom of the motor flange in an effort to stiffen the motor pump system, the motor vibrations went up due to more energy being transmitted from the pipe-pump system into the motor.
NLS2015026 Attachment 2 Page 27 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
: 5.       Testing was performed to determine any weaknesses in the pump-motor mechanical system. The vibration amplitude using the IRD instrument, with the filter set at operating speed, sampled many points vertically along the pump-motor structure. Plots of the data (along with phase angle determined by means of the strobe light) showed very clearly that the total structure was vibrating as a rigid assembly from the floor mounting. Examination of the high amplitude vibration signals showed them to be at the extremely low system natural frequencies as determined earlier.
Following the DC 94-046 testing, CNS noted that the deflections observed in the discharge piping were significantly reduced. Based on these results, it was determined by the Nuclear Engineering Department, Civil/Structural Group, that the CS Loop B piping vibration stresses are less than the endurance limit of the piping.On October 17, 2002, a Plant Engineering Supervisor at CNS, knowledgeable in the area of pump vibration analysis, issued a memo to the CNS Risk & Regulatory Affairs Manager discussing the low frequency vibration issue with the CS-P-B.In the memo, it is stated that the pipe is vibrating as a reaction to flow turbulence, which in turn is causing the pump to vibrate. The memo documents the basis for why the low frequency vibration (less than one-half pump running speed) experienced during CS-P-B operation is not indicative of degrading pump performance and is not expected to adversely impact pump operability.
: 6.       Such low acceleration levels, along with the system acting as a rigid structure (between motor and pump), means that the motor and pump can operate
To summarize, in the area of pump performance, aside from the randomness of the low frequency peaks, the spectral data shows no degrading trend in performance over several years of data. The low frequency piping-induced vibrations are not expected to adversely impact pump operability.
 
C. Independent Industry Vibration Expert Evaluation of CS-P-B In 2001, Machinery Solutions, Inc. was retained to perform an independent study of the CS-P-B vibrations.
NLS2015026 Page 26 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) with these levels of vibration with absolutely no impairment of operating life.
The following discussion was obtained from their report, issued in September of 2001. Machinery Solutions, Inc. utilized seven transducers and acquired data from CS-P-B continuously while it was operating, and data was stored every 3 seconds. Orbit plots, spectrum plots, bode and polar plots, cascade/waterfall plots, overall amplitude plots, trend plots, XY graph plots, and tabular lists were utilized to analyze the data. The data obtained by Machinery Solutions, Inc., indicated that the vibration amplitudes during the run were much higher at the top of the motor than they were at the bottom of the motor. The amplitudes decreased even further on the pump.The spectrum plots showed that most of the vibration was occurring below running speed. They also showed that the low frequency vibration is a different frequency in each direction.
This is the picture that seems very clearly described by the data obtained during these tests. There is absolutely no reason to restrict the operation of these pumps in any way.
The predominant peaks occur at approximately 870 cpm (less than one-half pump running speed) in line with discharge and at approximately 630 cpm (less than one-half pump running speed) perpendicular to discharge.
Although the vibration was found to be acceptable, CNS took actions to install new pipe supports as an attempt to reduce these piping-induced vibrations. This action was successful as will be discussed in a later section of this relief request.
The amplitude of each of these peaks varied significantly from second to second. The natural frequency of the pump-motor-piping structure was determined via impact testing prior to starting the pump. The natural frequencies were determined to be approximately 830 cpm in line with discharge and 670 cpm perpendicular to discharge.
B. CNS Expert Analysis of CS-P-B Vibrations As the Vibration Monitoring Program expanded in the early 1990s, it became evident that the low frequency, piping-induced vibrations still remained in CS-P-B. Design Change (DC) 94-046 resulted in the replacement of the orifices in the test return line. A March 16, 1995, memo to the CNS IST Engineer from the CNS Lead Civil/Structural Engineer discussed the CS-P-B vibration measurements obtained during DC 94-046 acceptance testing.
Such a vibration response is typical for vertical pumps.
The vibration data was collected using peak velocity measuring instrumentation as required for the performance of the IST test and with instrumentation that provides displacement and velocity versus frequency data. It was observed that the significant vibrations in the 1H direction were occurring around 700 cycles per minute (cpm), while the pump speed is at 1780 cpm (i.e., rpm). Given the piping movement of the system, and the knowledge that piping vibrations can commonly occur in the 700 cpm (12 Hz) range, CNS concluded that the pump vibrations were piping dependent.
NLS2015026 Attachment 2 Page 28 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
The CNS Lead Civil/Structural Engineer concluded that the significant pump vibrations are occurring at less than one-half of the pump operating speed. The pumps are rigidly mounted at their bases, and any impeller-induced vibrations would occur at the pump running speed or at the vane passing frequency. Therefore, the sub-synchronous pump vibrations are clearly piping induced, non-detrimental to pump/motor service or reliability, and should not be used as a basis for pump degradation. This is because the purpose of pump in-service testing is to diagnose and trend internal pump degradation.
The memo further states that the vibration data collection requirement specified in the IST procedure consists of peak velocity recordings, which may be masked by piping-induced vibrations, negating internal pump degradation diagnosis and trending. Based on the historical trending data for both CS pumps, the vibration has remained at a consistent amplitude, trending neither upward nor downward, indicating that the induced vibrations are not impairing pump operability, nor capable of preventing the pump from fulfilling its safety function. The piping vibration is present when flow is present through the test return line. It was visually observed during DC 94-046 acceptance testing that piping vibrations were minimal when flow was directed through the minimum flow line.
 
NLS2015026 Page 27 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Following the DC 94-046 testing, CNS noted that the deflections observed in the discharge piping were significantly reduced. Based on these results, it was determined by the Nuclear Engineering Department, Civil/Structural Group, that the CS Loop B piping vibration stresses are less than the endurance limit of the piping.
On October 17, 2002, a Plant Engineering Supervisor at CNS, knowledgeable in the area of pump vibration analysis, issued a memo to the CNS Risk & Regulatory Affairs Manager discussing the low frequency vibration issue with the CS-P-B.
In the memo, it is stated that the pipe is vibrating as a reaction to flow turbulence, which in turn is causing the pump to vibrate. The memo documents the basis for why the low frequency vibration (less than one-half pump running speed) experienced during CS-P-B operation is not indicative of degrading pump performance and is not expected to adversely impact pump operability. To summarize, in the area of pump performance, aside from the randomness of the low frequency peaks, the spectral data shows no degrading trend in performance over several years of data. The low frequency piping-induced vibrations are not expected to adversely impact pump operability.
C. Independent Industry Vibration Expert Evaluation of CS-P-B In 2001, Machinery Solutions, Inc. was retained to perform an independent study of the CS-P-B vibrations. The following discussion was obtained from their report, issued in September of 2001. Machinery Solutions, Inc. utilized seven transducers and acquired data from CS-P-B continuously while it was operating, and data was stored every 3 seconds. Orbit plots, spectrum plots, bode and polar plots, cascade/waterfall plots, overall amplitude plots, trend plots, XY graph plots, and tabular lists were utilized to analyze the data. The data obtained by Machinery Solutions, Inc., indicated that the vibration amplitudes during the run were much higher at the top of the motor than they were at the bottom of the motor. The amplitudes decreased even further on the pump.
The spectrum plots showed that most of the vibration was occurring below running speed. They also showed that the low frequency vibration is a different frequency in each direction. The predominant peaks occur at approximately 870 cpm (less than one-half pump running speed) in line with discharge and at approximately 630 cpm (less than one-half pump running speed) perpendicular to discharge. The amplitude of each of these peaks varied significantly from second to second. The natural frequency of the pump-motor-piping structure was determined via impact testing prior to starting the pump. The natural frequencies were determined to be approximately 830 cpm in line with discharge and 670 cpm perpendicular to discharge. Such a vibration response is typical for vertical pumps.
 
NLS2015026 Page 28 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Machinery Solutions, Inc. concluded the following:
Machinery Solutions, Inc. concluded the following:
I1. Most of the vibration that is measured on the motor casing is due to excitation of the structural resonances of the motor/pump by turbulent flow. These structural resonances are poorly damped and can be easily excited. Most vertical pumps have similar types of behavior, and it is not necessarily problematic by itself. A problem occurs when a pump has a continuous forcing function whose frequency coincides with a resonance (i.e., running speed). The forcing function in this case is flow turbulence caused in large part by the S-curve in the piping just off the pump discharge.
I1. Most of the vibration that is measured on the motor casing is due to excitation of the structural resonances of the motor/pump by turbulent flow. These structural resonances are poorly damped and can be easily excited. Most vertical pumps have similar types of behavior, and it is not necessarily problematic by itself. A problem occurs when a pump has a continuous forcing function whose frequency coincides with a resonance (i.e., running speed). The forcing function in this case is flow turbulence caused in large part by the S-curve in the piping just off the pump discharge. The flow through this area generates lateral broadband forces, due to elbow effects, that excite the resonances in a non-continuous fashion. This is why the amplitude swings so dramatically on the motor case (the location of vibration points 1H and 5H). The system goes from brief periods of excitation to brief periods of no excitation. The discharge riser is also moving side to side from the same forces. Although the discharge piping configuration is both non-standard and less than optimum for this application, it poses no threat to the long-term reliability of either the pump or the motor. The only negative impact is on vibration levels relative to a generic standard.
The flow through this area generates lateral broadband forces, due to elbow effects, that excite the resonances in a non-continuous fashion. This is why the amplitude swings so dramatically on the motor case (the location of vibration points 1H and 5H). The system goes from brief periods of excitation to brief periods of no excitation.
: 2. The balance condition of the motor and pump are acceptable with no corrective action required at this time.
The discharge riser is also moving side to side from the same forces. Although the discharge piping configuration is both non-standard and less than optimum for this application, it poses no threat to the long-term reliability of either the pump or the motor. The only negative impact is on vibration levels relative to a generic standard.2. The balance condition of the motor and pump are acceptable with no corrective action required at this time.3. The shaft alignment between the motor and the pump is acceptable for long-term operation.
: 3. The shaft alignment between the motor and the pump is acceptable for long-term operation.
: 4. There is no evidence of motor bearing wear.Machinery Solutions, Inc. recommended the following actions: I1. Create a new IST vibration data point configuration within the data collector database to use an overall level that is generated from spectral data above 950 cpm. This will eliminate the energy from the resonances from the data set and still allow for protection from bearing degradation, impeller degradation, and motor malfunctions.
: 4. There is no evidence of motor bearing wear.
The only potential failure mode that could occur within this excluded frequency range would be a fundamental train pass frequency generated by a rolling element bearing. This frequency only occurs with increased bearing clearance.
Machinery Solutions, Inc. recommended the following actions:
On vertical machines, this increased bearing clearance causes increased bearing compliance and the I X component will become larger. The I X change will be evident in the monitored data set.
I1. Create a new IST vibration data point configuration within the data collector database to use an overall level that is generated from spectral data above 950 cpm. This will eliminate the energy from the resonances from the data set and still allow for protection from bearing degradation, impeller degradation, and motor malfunctions. The only potential failure mode that could occur within this excluded frequency range would be a fundamental train pass frequency generated by a rolling element bearing. This frequency only occurs with increased bearing clearance.
NLS2015026 Attachment 2 Page 29 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
On vertical machines, this increased bearing clearance causes increased bearing compliance and the IX component will become larger. The IX change will be evident in the monitored data set.
: 2. Continue to acquire the old data points with the low-frequency data "for information only" to verify that the system response does not change.HI. Attempts to Lower Vibration (Key Component No. 3)CNS installed additional pipe restraints during the preoperational period in order to reduce piping-induced vibrations.
 
Testing on October 26 and 27, 1973, following the installation of these new supports, demonstrated significantly reduced vibrations.
NLS2015026 Page 29 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Low-frequency piping-induced vibrations continued, but with reduced amplitude following the installation of the pipe restraints.
: 2.       Continue to acquire the old data points with the low-frequency data "for information only" to verify that the system response does not change.
However, the issue resurfaced in the early 1990s when additional vibration points were recorded, more strict acceptance criteria were adopted for vibrations, and new technology was incorporated into the CNS vibration program.These new points were more influenced by the low-frequency piping-induced vibrations than the one or two points recorded in the 1980s. It was evident that the piping-induced vibrations were still prevalent with the CS-P-B pump.In 1993, a deficiency report was written to address increased frequency IST testing of CS-P-B due to vibration.
HI. Attempts to Lower Vibration (Key Component No. 3)
It was suspected that the pump vibrations were piping induced.Preliminary investigation of the vibration issue concluded that cavitation at the CS test return line throttle valve and/or restriction orifices was likely causing the elevated piping vibration in both CS System loops. Vibration testing of the CS piping confirmed this conclusion.
CNS installed additional pipe restraints during the preoperational period in order to reduce piping-induced vibrations. Testing on October 26 and 27, 1973, following the installation of these new supports, demonstrated significantly reduced vibrations. Low-frequency piping-induced vibrations continued, but with reduced amplitude following the installation of the pipe restraints. However, the issue resurfaced in the early 1990s when additional vibration points were recorded, more strict acceptance criteria were adopted for vibrations, and new technology was incorporated into the CNS vibration program.
To reduce these flow-induced vibrations, DC 94-046 was developed to replace the existing simple, single-stage orifices on both CS subsystem test return lines with multi-stage orifices.
These new points were more influenced by the low-frequency piping-induced vibrations than the one or two points recorded in the 1980s. It was evident that the piping-induced vibrations were still prevalent with the CS-P-B pump.
Post-installation testing with these multi-stage orifices demonstrated lower vibration levels on CS-P-A, but higher vibration levels on CS-P-B. A multi-hole single-stage orifice was fabricated and installed in the CS-P-B test return line (and later in the CS-P-A test return line) with significantly improved results. Visual observation and vibration data collected during acceptance testing determined that CS-P-B pump vibrations had been reduced, but one direction (location 1 H in Figure 1) still demonstrated peak velocity reading in the alert range. The pump vibrations in the 1 H direction were occurring at frequencies much lower than the pump operating speed.The major vibration peaks were occurring at approximately 700 (cpm), while the pump speed is at 1780 cpm, indicating that the vibration was piping induced. It was also observed during acceptance testing that vibrations were minimal during operation in the minimum flow condition.
In 1993, a deficiency report was written to address increased frequency IST testing of CS-P-B due to vibration. It was suspected that the pump vibrations were piping induced.
IV. Spectral Analysis (Key Component No. 4)Figures 7 through 11 in this relief request show spectrum plots for CS-P-B, as well as spectrum trends. These plots show that the peak energy spikes for points 1 H and 5H NLS2015026 Attachment 2 Page 30 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) remain below one-half pump running speed and that the pump vibration signature remains fairly uniform. Figure 12 shows that pump differential pressure is consistently acceptable.
Preliminary investigation of the vibration issue concluded that cavitation at the CS test return line throttle valve and/or restriction orifices was likely causing the elevated piping vibration in both CS System loops. Vibration testing of the CS piping confirmed this conclusion.
This data validates the analysis performed by Machinery Solutions, Inc., and the earlier conclusions that the elevated vibrations are piping induced, and not indicative of degraded pump performance.
To reduce these flow-induced vibrations, DC 94-046 was developed to replace the existing simple, single-stage orifices on both CS subsystem test return lines with multi-stage orifices. Post-installation testing with these multi-stage orifices demonstrated lower vibration levels on CS-P-A, but higher vibration levels on CS-P-B. A multi-hole single-stage orifice was fabricated and installed in the CS-P-B test return line (and later in the CS-P-A test return line) with significantly improved results. Visual observation and vibration data collected during acceptance testing determined that CS-P-B pump vibrations had been reduced, but one direction (location 1H in Figure 1) still demonstrated peak velocity reading in the alert range. The pump vibrations in the 1H direction were occurring at frequencies much lower than the pump operating speed.
No pump or motor faults and/or degradation are evident in the spectral analysis for this pump. This test data also shows that the vibrations experienced remain in the region of the CS-P-B pump-motor-piping system natural frequency, at less than half the pump's operating speed.Vibrations occurring at these low frequencies are not expected to be detrimental to the long-term reliability of either the pump or the motor. Typical pump faults, i.e., impeller wear, bearing problems, alignment problems, shaft bow, etc., would result in measurable vibration response in frequencies equal to or greater than one-half of the pump's running speed. Such faults would also be evident in pump trends. However, the vibrations are being experienced below one-half pump operating speed, have existed since initial operation, and are not trending higher. Visual inspection by Machinery Solutions, Inc., in 2001 of the pump base plate, soleplate, and grout, identified no visible cracks or degradation.
The major vibration peaks were occurring at approximately 700 (cpm), while the pump speed is at 1780 cpm, indicating that the vibration was piping induced. It was also observed during acceptance testing that vibrations were minimal during operation in the minimum flow condition.
Further, they concluded that the balance condition and shaft alignment of the pump and motor were acceptable, and detected no evidence of motor bearing wear.D. Maintenance History The maintenance history for CS-P-B reflects that there have been no significant work items applicable to CS-P-B due to the low-frequency vibrations that have been experienced since the construction phase of the plant. A review of maintenance history for the CS-P-B pump and motor was performed.
IV. Spectral Analysis (Key Component No. 4)
The search consisted of a historical review of CS-P-B pump and motor maintenance in addition to a more general search of CS System vibrational issues. This search identified that the pump and motor installed in the plant today is the same combination that was installed during the construction phase of the plant. Some of the key items reviewed are summarized below: 1. 1973: Additional supports installed on "B" CS System during pre-operational stage. As discussed previously, this resulted in lowering CS-P-B vibrations.
Figures 7 through 11 in this relief request show spectrum plots for CS-P-B, as well as spectrum trends. These plots show that the peak energy spikes for points 1H and 5H
: 2. January 1977: Vibration eliminator on "B" CS test line, CS-VE7, required tightening of wall plate bolts per Maintenance Work Request (MWR) 77-1-10.Bolts in pipe clamp were replaced and clamp was realigned.
 
Design was determined to be adequate, but lock washers should be used to prevent recurrence of the problem. MWR 77-1-262 completed this action.
NLS2015026 Page 30 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) remain below one-half pump running speed and that the pump vibration signature remains fairly uniform. Figure 12 shows that pump differential pressure is consistently acceptable. This data validates the analysis performed by Machinery Solutions, Inc., and the earlier conclusions that the elevated vibrations are piping induced, and not indicative of degraded pump performance. No pump or motor faults and/or degradation are evident in the spectral analysis for this pump. This test data also shows that the vibrations experienced remain in the region of the CS-P-B pump-motor-piping system natural frequency, at less than half the pump's operating speed.
NLS2015026 Attachment 2 Page 31 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
Vibrations occurring at these low frequencies are not expected to be detrimental to the long-term reliability of either the pump or the motor. Typical pump faults, i.e., impeller wear, bearing problems, alignment problems, shaft bow, etc., would result in measurable vibration response in frequencies equal to or greater than one-half of the pump's running speed. Such faults would also be evident in pump trends. However, the vibrations are being experienced below one-half pump operating speed, have existed since initial operation, and are not trending higher. Visual inspection by Machinery Solutions, Inc., in 2001 of the pump base plate, soleplate, and grout, identified no visible cracks or degradation. Further, they concluded that the balance condition and shaft alignment of the pump and motor were acceptable, and detected no evidence of motor bearing wear.
: 3. April 1989 (Work Item [WI] 89-0269);
D. Maintenance History The maintenance history for CS-P-B reflects that there have been no significant work items applicable to CS-P-B due to the low-frequency vibrations that have been experienced since the construction phase of the plant. A review of maintenance history for the CS-P-B pump and motor was performed.
November 1991 (WI 91-1507), February 1993 (MWR #92-2876):
The search consisted of a historical review of CS-P-B pump and motor maintenance in addition to a more general search of CS System vibrational issues. This search identified that the pump and motor installed in the plant today is the same combination that was installed during the construction phase of the plant. Some of the key items reviewed are summarized below:
CS-P-B stator end turn bracing brackets inspected for stress corrosion cracking or unusual conditions such as loose bolts or bending.No cracks, loose bolts, or other unusual conditions were observed.4. March 1993: A magnetic particle examination of CS-P-B support attachment weld revealed an indication at Lug #5 of the pump support. The indication was ground out, repaired, and retested satisfactorily.
: 1.     1973: Additional supports installed on "B" CS System during pre-operational stage. As discussed previously, this resulted in lowering CS-P-B vibrations.
The indication was very small and would not have affected the overall stiffness of the pump. In 2003, no recurrence of this indication was identified.
: 2.       January 1977: Vibration eliminator on "B" CS test line, CS-VE7, required tightening of wall plate bolts per Maintenance Work Request (MWR) 77-1-10.
: 5. April 1993: Work Order #93-1631 was initiated due to mechanical seal leakage.A complete inspection of the pump/motor was also completed.
Bolts in pipe clamp were replaced and clamp was realigned. Design was determined to be adequate, but lock washers should be used to prevent recurrence of the problem. MWR 77-1-262 completed this action.
The pump was found with the keyway not properly aligned with the mechanical seal, causing the leakage. The impeller was found to have minor pitting at the base of the wear ring area. The pump casing and cover had minor erosion and pitting. No significant problems with the pump or motor were noted.6. July 1994: Bolt torque checked for lower end bell and lower bearing housing on CS-P-B motor due to a loose bolt found on the "A" RHR pump motor. No movement on lower bearing housing bolts. Movement of lower end bell bolts were as follows: 1/16 flat on #1, 3, 4, and 5 and no movement on #2, 6, 7, and 8.These were very minor adjustments.
 
: 7. Late 1994: DC 94-046 installs new orifices in CS-P-B test line. As previously discussed, this reduced piping deflections in the test line.8. Oil Samples (Dates: 09-22-95, 10-22-95, 11-24-95, 02-28-97, 03-26-98, 04-05-99, 01-24-00, 12-26-00, 10-28-02, 08-30-04, 01-05-05, 08-14-06, 02-28-07, 08-14-07, 02-11-08, 08-14-08, 02-19-09, 08-12-09, 02-09-10, 08-25-10, 03-11-11, 09-02-11, 12-13-11, 03-02-12, 08-24-12, 02-12-13, 08-13-13, 02-11-14, 08-13-14): Periodic Oil Sample Analysis of the upper and lower motor bearings in accordance with Preventive Maintenance Program. Results of CS-P-B Motor oil analysis were satisfactory with no corrective actions required.9. Numerous Visual Motor Inspections completed satisfactory (i.e., January of 2002): Visual motor inspection satisfactory per Work Order #4199724.10. February 2003: Notification  
NLS2015026 Page 31 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)
#10225272 identified an indication approximately 3/8" on a CS-P-B integral attachment (CS-PB-Al).
: 3. April 1989 (Work Item [WI] 89-0269); November 1991 (WI 91-1507), February 1993 (MWR #92-2876): CS-P-B stator end turn bracing brackets inspected for stress corrosion cracking or unusual conditions such as loose bolts or bending.
The indication is at the top of one of the small gusset supports where the gusset is welded to the cast pump NLS2015026 Attachment 2 Page 32 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) bowl extension (different spot than the 1993 indication).
No cracks, loose bolts, or other unusual conditions were observed.
Within Engineering Evaluation 03-030, the indication was determined to be on the gusset side of the weld and appears to be an incomplete fusion of the weld and not a service load-induced flaw. Poor accessibility was the most likely cause. Engineering Calculation 03-007 demonstrated that, even if the five minor gusset plates were ignored, the pump support is still qualified under the most severe design loads.This search of the maintenance history, covering a time period of approximately forty years, identified no significant maintenance or corrective actions that had to be implemented for the "B" CS pump and motor due to the piping-induced vibrations.
: 4. March 1993: A magnetic particle examination of CS-P-B support attachment weld revealed an indication at Lug #5 of the pump support. The indication was ground out, repaired, and retested satisfactorily. The indication was very small and would not have affected the overall stiffness of the pump. In 2003, no recurrence of this indication was identified.
Only minor indications were noted on the pump impeller and casing during the last significant motor/pump disassembly in 1993.No other documentation of pump/motor disassembly inspection results was found during this review. Oil analyses of the CS-P-B lower and upper motor bearing housings were found to be satisfactory for all the results documented since 1995 to the present. Wear metals, contaminants, additives, etc., were all at acceptable levels. The addition of pipe supports in 1973 and new orifices in the test lines were necessary modifications and were previously discussed.
: 5. April 1993: Work Order #93-1631 was initiated due to mechanical seal leakage.
Other than these modifications, only minor corrections have been made with pipe and/or pump supports (tightening bolts, minor indication, etc.), none of which were found to be significant.
A complete inspection of the pump/motor was also completed. The pump was found with the keyway not properly aligned with the mechanical seal, causing the leakage. The impeller was found to have minor pitting at the base of the wear ring area. The pump casing and cover had minor erosion and pitting. No significant problems with the pump or motor were noted.
Therefore, the maintenance history supports the basis of this relief request in that the piping-induced vibrations occurring on CS-P-B have not degraded the pump or motor in any way.E. Basis for Code Alternative Alert Values for Points 1 H and 5H By this relief request, NPPD is proposing to increase the absolute alert limit for vibration points 11H and 5H from 0.325 in/s to 0.400 in/s. The piping-induced vibration, which occurs at low frequencies, occasionally causes the overall vibration value for these two points to exceed 0.325 in/s, resulting in CS-P-B being on an increased test frequency.
: 6. July 1994: Bolt torque checked for lower end bell and lower bearing housing on CS-P-B motor due to a loose bolt found on the "A" RHR pump motor. No movement on lower bearing housing bolts. Movement of lower end bell bolts were as follows: 1/16 flat on #1, 3, 4, and 5 and no movement on #2, 6, 7, and 8.
However, several expert analyses and maintenance history reviews have shown that this piping-induced vibration has not resulted in degradation to the pump. Additionally, the overall vibration levels have remained steady over the past -24.5 years. Therefore, it has been demonstrated that doubling the test frequency under the current conditions does not provide additional assurance as to the condition of the pump and its ability to perform its safety function.These new values are reasonable as they represent an alternative method that still meets the intended function of monitoring the pump for degradation over time while keeping the required action level unchanged.
These were very minor adjustments.
The proposed values encompass the majority of the historical values, but not all of them (reference Figures 2a, 2b, 3a, 3b). With these new values, a reading above 0.400 in/s would require NPPD to place the pump on an increased testing frequency and to evaluate the pump performance to determine the cause NLS2015026 Attachment 2 Page 33 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) of the reading. It is expected that a small amount of degradation occurring in the pump or a slight increase in the piping-induced vibration would be quickly identified with these new parameters.
: 7. Late 1994: DC 94-046 installs new orifices in CS-P-B test line. As previously discussed, this reduced piping deflections in the test line.
: 8. Oil Samples (Dates: 09-22-95, 10-22-95, 11-24-95, 02-28-97, 03-26-98, 04                   99, 01-24-00, 12-26-00, 10-28-02, 08-30-04, 01-05-05, 08-14-06, 02-28-07, 08-14-07, 02-11-08, 08-14-08, 02-19-09, 08-12-09, 02-09-10, 08-25-10, 03-11-11, 09-02-11, 12-13-11, 03-02-12, 08-24-12, 02-12-13, 08-13-13, 02-11-14, 08                   14): Periodic Oil Sample Analysis of the upper and lower motor bearings in accordance with Preventive Maintenance Program. Results of CS-P-B Motor oil analysis were satisfactory with no corrective actions required.
: 9. Numerous Visual Motor Inspections completed satisfactory (i.e., January of 2002): Visual motor inspection satisfactory per Work Order #4199724.
: 10. February 2003: Notification #10225272 identified an indication approximately 3/8" on a CS-P-B integral attachment (CS-PB-Al). The indication is at the top of one of the small gusset supports where the gusset is welded to the cast pump
 
NLS2015026 Page 32 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) bowl extension (different spot than the 1993 indication). Within Engineering Evaluation 03-030, the indication was determined to be on the gusset side of the weld and appears to be an incomplete fusion of the weld and not a service load-induced flaw. Poor accessibility was the most likely cause. Engineering Calculation 03-007 demonstrated that, even if the five minor gusset plates were ignored, the pump support is still qualified under the most severe design loads.
This search of the maintenance history, covering a time period of approximately forty years, identified no significant maintenance or corrective actions that had to be implemented for the "B" CS pump and motor due to the piping-induced vibrations. Only minor indications were noted on the pump impeller and casing during the last significant motor/pump disassembly in 1993.
No other documentation of pump/motor disassembly inspection results was found during this review. Oil analyses of the CS-P-B lower and upper motor bearing housings were found to be satisfactory for all the results documented since 1995 to the present. Wear metals, contaminants, additives, etc., were all at acceptable levels. The addition of pipe supports in 1973 and new orifices in the test lines were necessary modifications and were previously discussed. Other than these modifications, only minor corrections have been made with pipe and/or pump supports (tightening bolts, minor indication, etc.), none of which were found to be significant. Therefore, the maintenance history supports the basis of this relief request in that the piping-induced vibrations occurring on CS-P-B have not degraded the pump or motor in any way.
E. Basis for Code Alternative Alert Values for Points 1H and 5H By this relief request, NPPD is proposing to increase the absolute alert limit for vibration points 11H and 5H from 0.325 in/s to 0.400 in/s. The piping-induced vibration, which occurs at low frequencies, occasionally causes the overall vibration value for these two points to exceed 0.325 in/s, resulting in CS-P-B being on an increased test frequency.
However, several expert analyses and maintenance history reviews have shown that this piping-induced vibration has not resulted in degradation to the pump. Additionally, the overall vibration levels have remained steady over the past -24.5 years. Therefore, it has been demonstrated that doubling the test frequency under the current conditions does not provide additional assurance as to the condition of the pump and its ability to perform its safety function.
These new values are reasonable as they represent an alternative method that still meets the intended function of monitoring the pump for degradation over time while keeping the required action level unchanged. The proposed values encompass the majority of the historical values, but not all of them (reference Figures 2a, 2b, 3a, 3b). With these new values, a reading above 0.400 in/s would require NPPD to place the pump on an increased testing frequency and to evaluate the pump performance to determine the cause
 
NLS2015026 Page 33 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) of the reading. It is expected that a small amount of degradation occurring in the pump or a slight increase in the piping-induced vibration would be quickly identified with these new parameters.
The new alert limits will still allow for early detection of pump degradation or piping-induced vibration increases prior to component failure, while the required action absolute limit will remain at the code value of 0.700 in/s. Therefore, the intent of the code will be maintained.
The new alert limits will still allow for early detection of pump degradation or piping-induced vibration increases prior to component failure, while the required action absolute limit will remain at the code value of 0.700 in/s. Therefore, the intent of the code will be maintained.
Conclusions Several expert evaluations have documented that no internal pump or motor degradation is occurring due to the piping-induced vibration, which has been present since the pre-operational testing time period. The available vibration data over the past -24.5 years and differential pressure data over nearly the past -20 years supports this fact as
Conclusions Several expert evaluations have documented that no internal pump or motor degradation is occurring due to the piping-induced vibration, which has been present since the pre-operational testing time period. The available vibration data over the past -24.5 years and differential pressure data over nearly the past -20 years supports this fact as essentially no degradation has been indicated. A maintenance history review and review of oil analyses results further supports these conclusions.
Based on this information, CNS concludes that doubling the test frequency for CS-P-B does not provide additional information nor does it provide additional assurance as to the condition of the pump and its ability to perform its safety function. Testing of this pump on an increased frequency places an unnecessary burden on CNS resources.
All four key components discussed in NUREG/CP-0 152 have been addressed in detail, supporting the alternative testing recommended in this relief request.
CNS concludes that CS-P-B is operating acceptably and will perform its safety function as required during normal and accident conditions. The increased alert limits proposed for vibration points I H and 5H in this relief request will continue to assure long-term reliability of CS-P-B.
During the performance of CS-P-B inservice
ISTC-5153 Stroke Test Corrective Action.
ISTC-5153 Stroke Test Corrective Action.
NLS2015026 Attachment 2 Page 61 of 99 Relief Request RV-01 HPCI Solenoid Operated Drain Valve Testing (Continued)
 
: 4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the listed requirements of the ASME OM Code. The proposed alternative would provide an acceptable level of quality and safety.The HPCI turbine and exhaust steam drip leg drain to gland condenser (HPCI-SOV-SSV-64) and HPCI turbine and exhaust steam drip leg drain to equipment drain isolation valve (HPCI-SOV-SSV-87) have an active safety function in the closed position to maintain pressure boundary integrity of the HPCI turbine exhaust line. These valves serve as a Class 2 to non-code boundary barrier.These valves are rapid acting, encapsulated, solenoid-operated valves. Their control circuitry is provided with a remote manual switch for valve actuation to the open position and an auto function which allows the valves to actuate from signals received from the associated level switches HPCI-LS-98 and HPCI-LS-680.
NLS2015026 Page 61 of 99 Relief Request RV-01 HPCI Solenoid Operated Drain Valve Testing (Continued)
Both valves receive a signal to change disc position during testing of drain pot level switches.
: 4.     Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the listed requirements of the ASME OM Code. The proposed alternative would provide an acceptable level of quality and safety.
However, remote position indication is not provided for positive verification of disc position.
The HPCI turbine and exhaust steam drip leg drain to gland condenser (HPCI-SOV-SSV-64) and HPCI turbine and exhaust steam drip leg drain to equipment drain isolation valve (HPCI-SOV-SSV-87) have an active safety function in the closed position to maintain pressure boundary integrity of the HPCI turbine exhaust line. These valves serve as a Class 2 to non-code boundary barrier.
Additionally, their encapsulated design prohibits the ability to visually verify the physical position of the operator, stem, or internal components.
These valves are rapid acting, encapsulated, solenoid-operated valves. Their control circuitry is provided with a remote manual switch for valve actuation to the open position and an auto function which allows the valves to actuate from signals received from the associated level switches HPCI-LS-98 and HPCI-LS-680. Both valves receive a signal to change disc position during testing of drain pot level switches. However, remote position indication is not provided for positive verification of disc position. Additionally, their encapsulated design prohibits the ability to visually verify the physical position of the operator, stem, or internal components.
Modification of the system to verify valve closure capability and stroke timing is not practicable nor cost beneficial since no commensurate increase in safety would be derived.5. Proposed Alternative and Basis for Use CNS has been performing a robust exercise test for these two valves that verifies obturator movement since 1998 on a quarterly basis. In 2001, this test identified some leakage past HPCI-SOV-SSV64 and the valve was removed and refurbished.
Modification of the system to verify valve closure capability and stroke timing is not practicable nor cost beneficial since no commensurate increase in safety would be derived.
For the past -14 years, the exercise test has been completed without any issues. This test is accomplished through the performance of surveillance procedure, 6.HPCI.204, HPCI-SOV-SSV64 and HPCI-SOV-SSV87 IST Closure Test. With HPCI not in operation, a demineralized water source is utilized to verify that HPCI-SOV-SSV64 opens when level switch HPCI-LS-680 (turbine exhaust drain pot high level) trips, allowing level in the gland seal condenser to start to rise due to water flow through HPCI-SOV-SSV64. After HPCI-LS-680 resets and HPCI-SOV-SSV64 closes, the gland seal condenser level is verified to be steady.Similarly, CNS verifies that HPCI-SOV-SSV87 opens when level switch HPCI-LS-98 (turbine exhaust drip leg high) trips, allowing the observation of water flow to a floor drain from a drain pipe downstream of HPCI-SOV-SSV87.
: 5.     Proposed Alternative and Basis for Use CNS has been performing a robust exercise test for these two valves that verifies obturator movement since 1998 on a quarterly basis. In 2001, this test identified some leakage past HPCI-SOV-SSV64 and the valve was removed and refurbished. For the past -14 years, the exercise test has been completed without any issues. This test is accomplished through the performance of surveillance procedure, 6.HPCI.204, HPCI-SOV-SSV64 and HPCI-SOV-SSV87 IST Closure Test. With HPCI not in operation, a demineralized water source is utilized to verify that HPCI-SOV-SSV64 opens when level switch HPCI-LS-680 (turbine exhaust drain pot high level) trips, allowing level in the gland seal condenser to start to rise due to water flow through HPCI-SOV-SSV64. After HPCI-LS-680 resets and HPCI-SOV-SSV64 closes, the gland seal condenser level is verified to be steady.
After HPCI-LS-98 resets and HPCI-SOV-SSV87 closes, CNS observes the drain pipe downstream of HPCI-SOV-SSV87 for gross leakage past the valve.Therefore, CNS verifies valve obturator movement for both valves open and closed while simultaneously verifying the calibration of two level switches.Typically, tests that involve hooking up pressure sources and various amounts of test tubing are not performed on a quarterly basis due to their complexities (i.e. local leak rate tests). In addition, each time this "quarterly" test has been performed, HPCI unavailability time (-1.5 NLS2015026 Attachment 2 Page 62 of 99 Relief Request RV-01 IIPCI Solenoid Operated Drain Valve Testing (Continued) hours) is consumed in addition to some minor radiological dose. Finally, this exercise test is actually a much better method of determining the valve's operational readiness than a quarterly fast acting stroke time test would have been. Therefore, based on the complexities of the test, consuming unnecessary HPCI unavailability time and personnel radiation exposure, the exceptional test history dating back to 2001, and the fact that this is a robust test that verifies obturator movement, CNS proposes to exercise each valve to the full closed position, as described, on a 6 month basis.In addition to performing this robust exercise test every 6 months, each solenoid valve will be disassembled and examined for degradation on a periodic basis per the Preventative Maintenance Program. The valve body, insert, piston, plunger/stem assembly, and stem spring will all be examined per criteria outlined in surveillance procedure 6.HPCI.404.
Similarly, CNS verifies that HPCI-SOV-SSV87 opens when level switch HPCI-LS-98 (turbine exhaust drip leg high) trips, allowing the observation of water flow to a floor drain from a drain pipe downstream of HPCI-SOV-SSV87. After HPCI-LS-98 resets and HPCI-SOV-SSV87 closes, CNS observes the drain pipe downstream of HPCI-SOV-SSV87 for gross leakage past the valve.
In addition, continuity and the physical condition of the coil will also be checked. The valve and/or valve parts will be refurbished and/or replaced, as necessary, based on this examination.
Therefore, CNS verifies valve obturator movement for both valves open and closed while simultaneously verifying the calibration of two level switches.
This maintenance shall be performed at an optimized frequency, not to exceed 48 months (2 cycles). The purpose of this enhanced preventative maintenance is to ensure the long term reliability of the components and to monitor for internal degradation.
Typically, tests that involve hooking up pressure sources and various amounts of test tubing are not performed on a quarterly basis due to their complexities (i.e. local leak rate tests). In addition, each time this "quarterly" test has been performed, HPCI unavailability time (-1.5
This is consistent with NUREG 1482, Section 4.2.3. The 6 month exercise tests will ensure that the valves are operational and will fulfill their safety function when called upon.The robust 6 month exercise testing and the enhanced preventative maintenance will provide an adequate indication of valve performance and will continue to provide an acceptable level of quality and safety. Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTC requirements identified in this request.6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RV-01, Revision I (TAC NO. ME7021, August 28, 2012) and Revision 0 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).A version of this relief request was previously approved for the fifth ten-year interval at Dresden Nuclear Power Station as Relief Request RV-23H (TAC Nos. ME9865, ME9866, ME9869, ME9870, ME9871, and ME9872, October 31, 2013).
 
NLS2015026 Attachment 2 Page 63 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
NLS2015026 Page 62 of 99 Relief Request RV-01 IIPCI Solenoid Operated Drain Valve Testing (Continued) hours) is consumed in addition to some minor radiological dose. Finally, this exercise test is actually a much better method of determining the valve's operational readiness than a quarterly fast acting stroke time test would have been. Therefore, based on the complexities of the test, consuming unnecessary HPCI unavailability time and personnel radiation exposure, the exceptional test history dating back to 2001, and the fact that this is a robust test that verifies obturator movement, CNS proposes to exercise each valve to the full closed position, as described, on a 6 month basis.
Alternative Provides Acceptable Level of Quality and Safety 1. ASME Code Component(s)
In addition to performing this robust exercise test every 6 months, each solenoid valve will be disassembled and examined for degradation on a periodic basis per the Preventative Maintenance Program. The valve body, insert, piston, plunger/stem assembly, and stem spring will all be examined per criteria outlined in surveillance procedure 6.HPCI.404. In addition, continuity and the physical condition of the coil will also be checked. The valve and/or valve parts will be refurbished and/or replaced, as necessary, based on this examination. This maintenance shall be performed at an optimized frequency, not to exceed 48 months (2 cycles). The purpose of this enhanced preventative maintenance is to ensure the long term reliability of the components and to monitor for internal degradation. This is consistent with NUREG 1482, Section 4.2.3. The 6 month exercise tests will ensure that the valves are operational and will fulfill their safety function when called upon.
Affected Valve Class Category System MS-RV-70ARV 1 C Main Steam (MS)MS-RV-70BRV 1 C MS MS-RV-70CRV 1 C MS 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda 3. Applicable Code Requirement ISTC-5240  
The robust 6 month exercise testing and the enhanced preventative maintenance will provide an adequate indication of valve performance and will continue to provide an acceptable level of quality and safety. Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTC requirements identified in this request.
-Safety and Relief Valves. Safety and relief valves shall meet the inservice test requirements of Mandatory Appendix I.ASME OM Code Mandatory Appendix I, "Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants," Section 1-1320, "Test Frequencies, Class I Pressure Relief Valves," paragraph (a), "5-Year Test Interval," states that Class I pressure relief valves shall be tested at least once every 5 years.4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirements of ASME OM Code Appendix I, 1-1320(a).
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
The proposed alternative would provide an acceptable level of quality and safety.Section ISTC-3200, "Inservice Testing," states that inservice testing shall commence when the valves are required to be operable to fulfill their required function(s).
: 7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RV-01, Revision I (TAC NO. ME7021, August 28, 2012) and Revision 0 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
Section ISTC-5240, "Safety and Relief Valves," directs that safety and relief valves meet the inservice testing requirements set forth in Appendix I of the ASME OM Code. Appendix I, Section 1-1320(a), of the ASME OM Code states that Class 1 pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation.
A version of this relief request was previously approved for the fifth ten-year interval at Dresden Nuclear Power Station as Relief Request RV-23H (TAC Nos. ME9865, ME9866, ME9869, ME9870, ME9871, and ME9872, October 31, 2013).
This section also states a minimum of 20 percent of the pressure relief valves are tested within any 24-month interval and that the test interval for any individual valve shall not exceed 5 years. Prior to Cycle 28, CNS had refueling cycles of 18 months. With three safety valves, CNS has been meeting the ASME OM Code by removing, NLS2015026 Attachment 2 Page 64 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued) testing, rebuilding, and re-installing one valve per refueling outage. All three of these safety valves have an acceptable test history since 1997 as will be described in section 5.However, after Refueling Outage (RE) 27 (Fall/2012), CNS began the current 24-month refueling cycle. The five year frequency was met for the safety valve due in RE28 (Fall/2014), but a relief request, requesting the use of Code Case OMN-17, will be necessary in order to continue with the process of testing only one valve each refueling outage for the fifth ten-year interval, beginning March 1, 2016. Without this relief request, CNS would be required to remove and test all three valves within a two cycle frequency (two one outage and one the next) in order to ensure that all three valves are removed and tested in accordance with the ASME OM Code requirements.
 
This testing pattern would ensure compliance with the ASME OM Code requirements for testing Class 1 pressure relief valves within a 5 year interval.Extending the test interval to 6 years, as described in Code Case OMN-l17, would allow CNS to continue with the current method of removing, testing, rebuilding, and re-installing one safety valve per outage so that all three safety valves would be replaced over three refuel cycles (i.e., -6 years).Without Code relief, the incremental outage work due to the inclusion of an additional safety valve every other outage would be contrary to the principle of maintaining radiation dose As Low As Reasonably Achievable (ALARA). The removal and replacement of the additional safety valve every other outage results in an additional exposure of approximately 450 millirem (mrem) to 726 mrem. This estimate is based on the actual radiation received to remove and re-install a safety valve each of the last three refueling outages.In accordance with 10 CFR 50.55a(h)(3)(z)(1), NPPD requests approval of an alternative to the 5 year test interval requirement of the ASME OM Code, Appendix I, Section 1-1320(a) for the safety valves at CNS.5. Proposed Alternative and Basis for Use NPPD requests that the test interval be increased from 5 years to 6 years in accordance with Code Case OMN-17. All aspects of Code Case OMN-17 will be followed for the MS safety valves.As an alternative to the Code required 5-year test interval per Appendix I, paragraph 1-1320(a), NPPD proposes that the subject Class 1 safety valves be tested at least once every three refueling cycles (approximately 6 years/72 months) with a minimum of 20% of the valves tested within any 24-month interval.
NLS2015026 Page 63 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
This 20% would consist of valves that have not been tested during the current 72-month interval, if they exist. The test interval for any individual valve would not exceed 72 months except that a 6-month grace period is allowed to coincide with refueling outages to accommodate extended shutdown periods and certification of the valve prior to installation.
Alternative Provides Acceptable Level of Quality and Safety
This is all in accordance with OMN-17, paragraph (a).After as-found set-pressure testing, the valves shall be disassembled and inspected to verify that parts are free of defects resulting from time-related degradation or service induced wear. As-left NLS2015026 Attachment 2 Page 65 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued) set-pressure testing shall be performed following maintenance and prior to returning the valve to service. Each valve shall have been disassembled and inspected prior to the start of the 72-month interval.
: 1.     ASME Code Component(s) Affected Valve                 Class               Category                   System MS-RV-70ARV                   1                     C                 Main Steam (MS)
Disassembly and inspection performed prior to the implementation of Code Case OMN-17 may be used.Each refueling outage, CNS will remove one safety valve to be sent off-site to a test facility.Upon receipt at the off-site facility, the valves are subject to an as-found inspection, as-found seat leakage test, and as-found set pressure test in accordance with Appendix I of the ASME OM Code. Prior to the returning the valve to the plant for re-installation, the safety valve is disassembled and inspected to verify that internal surfaces and parts are free from defects or service induced wear. During this process, anomalies or damage are identified for resolution.
MS-RV-70BRV                   1                     C                         MS MS-RV-70CRV                   1                     C                         MS
: 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
: 3. Applicable Code Requirement ISTC-5240 - Safety and Relief Valves. Safety and relief valves shall meet the inservice test requirements of Mandatory Appendix I.
ASME OM Code Mandatory Appendix I, "Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants," Section 1-1320, "Test Frequencies, Class I Pressure Relief Valves," paragraph (a), "5-Year Test Interval," states that Class I pressure relief valves shall be tested at least once every 5 years.
: 4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirements of ASME OM Code Appendix I, 1-1320(a). The proposed alternative would provide an acceptable level of quality and safety.
Section ISTC-3200, "Inservice Testing," states that inservice testing shall commence when the valves are required to be operable to fulfill their required function(s). Section ISTC-5240, "Safety and Relief Valves," directs that safety and relief valves meet the inservice testing requirements set forth in Appendix I of the ASME OM Code. Appendix I, Section 1-1320(a), of the ASME OM Code states that Class 1 pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation. This section also states a minimum of 20 percent of the pressure relief valves are tested within any 24-month interval and that the test interval for any individual valve shall not exceed 5 years. Prior to Cycle 28, CNS had refueling cycles of 18 months. With three safety valves, CNS has been meeting the ASME OM Code by removing,
 
NLS2015026 Page 64 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued) testing, rebuilding, and re-installing one valve per refueling outage. All three of these safety valves have an acceptable test history since 1997 as will be described in section 5.
However, after Refueling Outage (RE) 27 (Fall/2012), CNS began the current 24-month refueling cycle. The five year frequency was met for the safety valve due in RE28 (Fall/2014), but a relief request, requesting the use of Code Case OMN-17, will be necessary in order to continue with the process of testing only one valve each refueling outage for the fifth ten-year interval, beginning March 1, 2016. Without this relief request, CNS would be required to remove and test all three valves within a two cycle frequency (two one outage and one the next) in order to ensure that all three valves are removed and tested in accordance with the ASME OM Code requirements. This testing pattern would ensure compliance with the ASME OM Code requirements for testing Class 1 pressure relief valves within a 5 year interval.
Extending the test interval to 6 years, as described in Code Case OMN-l17, would allow CNS to continue with the current method of removing, testing, rebuilding, and re-installing one safety valve per outage so that all three safety valves would be replaced over three refuel cycles (i.e., -6 years).
Without Code relief, the incremental outage work due to the inclusion of an additional safety valve every other outage would be contrary to the principle of maintaining radiation dose As Low As Reasonably Achievable (ALARA). The removal and replacement of the additional safety valve every other outage results in an additional exposure of approximately 450 millirem (mrem) to 726 mrem. This estimate is based on the actual radiation received to remove and re-install a safety valve each of the last three refueling outages.
In accordance with 10 CFR 50.55a(h)(3)(z)(1), NPPD requests approval of an alternative to the 5 year test interval requirement of the ASME OM Code, Appendix I, Section 1-1320(a) for the safety valves at CNS.
: 5. Proposed Alternative and Basis for Use NPPD requests that the test interval be increased from 5 years to 6 years in accordance with Code Case OMN-17. All aspects of Code Case OMN-17 will be followed for the MS safety valves.
As an alternative to the Code required 5-year test interval per Appendix I, paragraph 1-1320(a),
NPPD proposes that the subject Class 1 safety valves be tested at least once every three refueling cycles (approximately 6 years/72 months) with a minimum of 20% of the valves tested within any 24-month interval. This 20% would consist of valves that have not been tested during the current 72-month interval, if they exist. The test interval for any individual valve would not exceed 72 months except that a 6-month grace period is allowed to coincide with refueling outages to accommodate extended shutdown periods and certification of the valve prior to installation. This is all in accordance with OMN-17, paragraph (a).
After as-found set-pressure testing, the valves shall be disassembled and inspected to verify that parts are free of defects resulting from time-related degradation or service induced wear. As-left
 
NLS2015026 Page 65 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued) set-pressure testing shall be performed following maintenance and prior to returning the valve to service. Each valve shall have been disassembled and inspected prior to the start of the 72-month interval. Disassembly and inspection performed prior to the implementation of Code Case OMN-17 may be used.
Each refueling outage, CNS will remove one safety valve to be sent off-site to a test facility.
Upon receipt at the off-site facility, the valves are subject to an as-found inspection, as-found seat leakage test, and as-found set pressure test in accordance with Appendix I of the ASME OM Code. Prior to the returning the valve to the plant for re-installation, the safety valve is disassembled and inspected to verify that internal surfaces and parts are free from defects or service induced wear. During this process, anomalies or damage are identified for resolution.
Damaged or worn parts (i.e. springs, gaskets and seals) are replaced or repaired, as necessary.
Damaged or worn parts (i.e. springs, gaskets and seals) are replaced or repaired, as necessary.
Following reassembly, the valve's set pressure is recertified.
Following reassembly, the valve's set pressure is recertified. This existing process is in accordance with ASME OM Code Case OMN-17, paragraphs (d) and (e). Alternatively, CNS may elect to replace the removed valve with a spare valve that has previously already been through the process just described. Up to three spare valves may be used in accordance with paragraph (b) of OMN-17.
This existing process is in accordance with ASME OM Code Case OMN-17, paragraphs (d) and (e). Alternatively, CNS may elect to replace the removed valve with a spare valve that has previously already been through the process just described.
NPPD has reviewed the as-found set point test results for all three safety valves tested since 1997 as detailed in Table 1. Since 1997, all as found lift tests have been within a +/-3% tolerance (maximum of +2.02%). The current Technical Specification requirements are that the as found test results fall within a +/-3% tolerance. Technical Specifications require the as left certification of the valves to meet a +/-1% tolerance. If an as found test is found to be outside of the +/-3%
Up to three spare valves may be used in accordance with paragraph (b) of OMN-17.NPPD has reviewed the as-found set point test results for all three safety valves tested since 1997 as detailed in Table 1. Since 1997, all as found lift tests have been within a +/-3% tolerance (maximum of +2.02%). The current Technical Specification requirements are that the as found test results fall within a +/-3% tolerance.
tolerance, the other 2 safety valves will be removed and tested in accordance with Code Case OMN-17, paragraph (c).
Technical Specifications require the as left certification of the valves to meet a +/-1% tolerance.
Accordingly, the proposed alternative of implementing all aspects of OMN-1 7, which will increase the test interval for the subject Class 1 safety valves from 5 years to 3 fuel cycles (approximately 6 years/72 months), will provide an acceptable level of quality and safety. This will also restore the operational and maintenance flexibility that was lost when the 24-month fuel cycle created the unintended consequences of more frequent testing. This proposed alternative will continue to provide assurance of the valves' operational readiness and provides an acceptable level of quality and safety pursuant to 10 CFR 50.55a(h)(3)(z)(1).
If an as found test is found to be outside of the +/-3%tolerance, the other 2 safety valves will be removed and tested in accordance with Code Case OMN-17, paragraph (c).Accordingly, the proposed alternative of implementing all aspects of OMN-1 7, which will increase the test interval for the subject Class 1 safety valves from 5 years to 3 fuel cycles (approximately 6 years/72 months), will provide an acceptable level of quality and safety. This will also restore the operational and maintenance flexibility that was lost when the 24-month fuel cycle created the unintended consequences of more frequent testing. This proposed alternative will continue to provide assurance of the valves' operational readiness and provides an acceptable level of quality and safety pursuant to 10 CFR 50.55a(h)(3)(z)(1).
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents A similar relief was previously approved at Peach Bottom for the fourth ten-year interval as Relief Request 01A-VRR-3 (TAC Nos. MF2509 and MF2510, April 30, 2014).
: 7. Precedents A similar relief was previously approved at Peach Bottom for the fourth ten-year interval as Relief Request 01A-VRR-3 (TAC Nos. MF2509 and MF2510, April 30, 2014).
NLS2015026 Attachment 2 Page 66 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued)
 
NLS2015026 Page 66 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued)
Monticello Nuclear Generating Plant Relief Request VR-04 was approved in a NRC Safety Evaluation Report dated September 26, 2012 (ML12244A272).
Monticello Nuclear Generating Plant Relief Request VR-04 was approved in a NRC Safety Evaluation Report dated September 26, 2012 (ML12244A272).
Quad Cites Nuclear Power Station, Units I and 2 Relief Request RV-05 was approved in a NRC Safety Evaluation Report dated February 14, 2013 (ML13042A348).
Quad Cites Nuclear Power Station, Units I and 2 Relief Request RV-05 was approved in a NRC Safety Evaluation Report dated February 14, 2013 (ML13042A348).
Table 1: Cooper Nuclear Station Safety Valve Test History Safety Valve AF Test Date Set Pressure As Found Set Deviation from Pressure Set Pressure 4/9/1997 1240 1217 -1.85%10/9/1998 1240 1252 +0.97%MS-RV-70ARV 3/8/2003 1240 1226 -1.13%4/19/2008 1240 1232 -0.65%10/21/2012 1240 1255 +1.21%4/10/1997 1240 1226 -1.13%3/12/2000 1240 1231 -0.73%MS-RV-70BRV 1/25/2005 1240 1241 +0.08%10/3/2009 1240 1260 +1.61%10/8/2014 1240 1253 +1.05%4/10/1997 1240 1262 +1.77%11/12/2001 1240 1237 -0.24%MS-RV-70CRV 10/26/2006 1240 1265 +2.02%3/21/2011 1240 1262 +1.77%
Table 1: Cooper Nuclear Station Safety Valve Test History AF Test Date         Set Pressure         As Found Set       Deviation from Safety Valve Pressure         Set Pressure 4/9/1997               1240                 1217             -1.85%
NLS2015026 Attachment 2 Page 67 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
10/9/1998             1240                 1252             +0.97%
Alternative Provides Acceptable Level of Quality and Safety 1. ASME Code Component(s)
MS-RV-70ARV             3/8/2003               1240                 1226             -1.13%
Affected Valve Class Category System MS-RV-71ARV 1 B/C MS MS-RV-71BRV 1 B/C MS MS-RV-71CRV 1 B/C MS MS-RV-71DRV 1 B/C MS MS-RV-71ERV 1 B/C MS MS-RV-71FRV 1 B/C MS MS-RV-71GRV 1 B/C MS MS-RV-71HRV 1 B/C MS 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda 3. Applicable Code Requirement ISTC-5240  
4/19/2008               1240                 1232             -0.65%
-Safety and Relief Valves. Safety and relief valves shall meet the inservice test requirements of Mandatory Appendix I.ASME OM Code Mandatory Appendix I, "Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants," Section 1-1320, "Test Frequencies, Class 1 Pressure Relief Valves," paragraph (a), "5-Year Test Interval," states that Class 1 pressure relief valves shall be tested at least once every 5 years.ASME OM Code Mandatory Appendix I, 1-3310 Class I Main Steam Pressure Relief Valves with Auxiliary Actuation Devices -Tests before maintenance or set-pressure adjustment, or both, shall be performed for 1-3310(a), (b) and (c) in sequence.
10/21/2012             1240                 1255             +1.21%
The remaining shall be performed after maintenance or set-pressure adjustments:
4/10/1997               1240                 1226             -1.13%
: a. visual examination; NLS2015026 Attachment 2 Page 68 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)
3/12/2000               1240                 1231             -0.73%
MS-RV-70BRV             1/25/2005             1240                 1241             +0.08%
10/3/2009             1240                 1260             +1.61%
10/8/2014             1240                 1253             +1.05%
4/10/1997               1240                 1262             +1.77%
11/12/2001             1240                 1237             -0.24%
MS-RV-70CRV 10/26/2006             1240                 1265             +2.02%
3/21/2011               1240                 1262             +1.77%
 
NLS2015026 Page 67 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
Alternative Provides Acceptable Level of Quality and Safety
: 1. ASME Code Component(s) Affected Valve                 Class               Category                 System MS-RV-71ARV                 1                     B/C                     MS MS-RV-71BRV                 1                     B/C                     MS MS-RV-71CRV                 1                     B/C                     MS MS-RV-71DRV                 1                     B/C                     MS MS-RV-71ERV                 1                     B/C                     MS MS-RV-71FRV                 1                     B/C                     MS MS-RV-71GRV                 1                     B/C                     MS MS-RV-71HRV                 1                     B/C                     MS
: 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
: 3. Applicable Code Requirement ISTC-5240 - Safety and Relief Valves. Safety and relief valves shall meet the inservice test requirements of Mandatory Appendix I.
ASME OM Code Mandatory Appendix I, "Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants," Section 1-1320, "Test Frequencies, Class 1 Pressure Relief Valves," paragraph (a), "5-Year Test Interval," states that Class 1 pressure relief valves shall be tested at least once every 5 years.
ASME OM Code Mandatory Appendix I, 1-3310 Class I Main Steam Pressure Relief Valves with Auxiliary Actuation Devices - Tests before maintenance or set-pressure adjustment, or both, shall be performed for 1-3310(a), (b) and (c) in sequence. The remaining shall be performed after maintenance or set-pressure adjustments:
: a. visual examination;
 
NLS2015026 Page 68 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)
: b. seat tightness determination, if practicable;
: b. seat tightness determination, if practicable;
: c. set-pressure determination;
: c. set-pressure determination;
: d. determination of electrical characteristics and pressure integrity of solenoid valve(s);e. determination of pressure integrity and stroke capability of air actuator;f. determination of operation and electrical characteristics of position indicators;
: d. determination of electrical characteristics and pressure integrity of solenoid valve(s);
: g. determination of operation and electrical characteristics of bellows arm switch;h. determination of actuating pressure of auxiliary actuating device sensing element, where applicable, and electrical continuity;
: e. determination of pressure integrity and stroke capability of air actuator;
: i. determination of compliance with the Owner's seat tightness criteria.4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirements of ASME OM Code Appendix I, sections 1-1320(a) and 1-3310. The proposed alternative would provide an acceptable level of quality and safety.Section ISTC-5240, "Safety and Relief Valves," directs that safety and relief valves meet the inservice testing requirements set forth in Appendix I of the ASME OM Code.Appendix I, Section I-1320(a), of the ASME OM Code states that Class 1 pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation.
: f. determination of operation and electrical characteristics of position indicators;
This section also states a minimum of 20 percent of the pressure relief valves are tested within any 24-month interval and that the test interval for any individual valve shall not exceed 5 years.CNS has eight MS safety relief valves (SRV). The approach for the past several years has been to remove either 2 or 3 of the entire valves (i.e. main body and pilot assembly) every refueling outage and send them off for as found testing, refurbishment, rebuilding, and re-certification in preparation for the next time they are re-installed into the plant. Those 2 or 3 entire valves have been replaced with refurbished valves that were recertified just prior to the outage. The schedule is planned so that all eight entire valves get sent off, as found tested, refurbished, and re-certified within a three cycle frequency.
: g. determination of operation and electrical characteristics of bellows arm switch;
In addition, CNS has replaced the remainder of the pilot assemblies (5 or 6 per outage) and sent them off for testing, refurbishment, and re-certification in preparation for the next time they are re-installed into the plant. These 5 or 6 additional pilot assemblies are replaced with refurbished and recertified pilot assemblies that were recertified just prior to the outage. Therefore, the pilot assemblies for the full complement of 8 valves have been set pressure tested every outage for several years.
: h. determination of actuating pressure of auxiliary actuating device sensing element, where applicable, and electrical continuity;
NLS2015026 Attachment 2 Page 69 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)
: i. determination of compliance with the Owner's seat tightness criteria.
CNS plans to continue this approach into the fifth ten-year interval.
: 4.     Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirements of ASME OM Code Appendix I, sections 1-1320(a) and 1-3310. The proposed alternative would provide an acceptable level of quality and safety.
However, refueling outage 27 (Fall/2012) was the last refueling outage under an 18-month cycle. CNS is now operating with 24-month cycles. With this in mind, the refurbishment of the entire valves will eventually align with a six year frequency, which is consistent with Code Case OMN-1 7. However, all eight of the pilot assemblies are being removed, tested and replaced with refurbished/recertified spare pilot assemblies every refueling outage, which means a full complement of the set pressure portion of the valves are being tested every refueling outage. Therefore, although this approach is very conservative, documenting acceptability of this approach is being pursued per this relief request.Additionally, since 5-6 pilot assemblies, alone, are being replaced every outage (versus the entire valve), documenting acceptability of how portions of Appendix 1-33 10 are being satisfied is also being pursued per this relief request.5. Proposed Alternative and Basis for Use These eight SRVs are considered Class 1 main steam pressure relief valves with auxiliary actuating devices. They are located on the main steam lines. In addition to their automatic function of opening to prevent over pressurization of the reactor vessel, six of these valves are associated with the Automatic Depressurization System and two are associated with the Low Low Set logic. The valves are two-stage Target Rock valves, each equipped with a main body, a pilot assembly for set pressure control, a solenoid valve, and an air operator assembly.CNS proposes to follow the Code Case OMN-17, paragraph (d), recommendations for Maintenance on these eight valves. Therefore, on a three cycle (up to 6 year) frequency, CNS proposes to remove the entire valve unit (i.e. main body and pilot assembly) for each one of these valves and ship it off for as found testing, refurbishment, and re-certification.
Section ISTC-5240, "Safety and Relief Valves," directs that safety and relief valves meet the inservice testing requirements set forth in Appendix I of the ASME OM Code.
CNS will replace these entire valve units with spare refurbished and re-certified entire valve units.As mentioned earlier, each valve is equipped with a pilot valve assembly that controls the set pressure.
Appendix I, Section I-1320(a), of the ASME OM Code states that Class 1 pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation. This section also states a minimum of 20 percent of the pressure relief valves are tested within any 24-month interval and that the test interval for any individual valve shall not exceed 5 years.
The remainder of the pilot valve assemblies (5 or 6 per refueling outage) will be removed from the main body and sent off site for examination, as found testing, refurbishment, and re-qualification testing (set point, reseat, and pilot stage seat tightness).
CNS has eight MS safety relief valves (SRV). The approach for the past several years has been to remove either 2 or 3 of the entire valves (i.e. main body and pilot assembly) every refueling outage and send them off for as found testing, refurbishment, rebuilding, and re-certification in preparation for the next time they are re-installed into the plant. Those 2 or 3 entire valves have been replaced with refurbished valves that were recertified just prior to the outage. The schedule is planned so that all eight entire valves get sent off, as found tested, refurbished, and re-certified within a three cycle frequency. In addition, CNS has replaced the remainder of the pilot assemblies (5 or 6 per outage) and sent them off for testing, refurbishment, and re-certification in preparation for the next time they are re-installed into the plant. These 5 or 6 additional pilot assemblies are replaced with refurbished and recertified pilot assemblies that were recertified just prior to the outage. Therefore, the pilot assemblies for the full complement of 8 valves have been set pressure tested every outage for several years.
The test facility has a main body slave for this purpose. The removed pilot valve assemblies are replaced with previously refurbished and re-qualified pilot valve assemblies.
 
By testing all of the pilot valve assemblies every outage, the potential need to expand to test additional valves due to set pressure failures is alleviated and the future valve reliability is improved.
NLS2015026 Page 69 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)
Test results are being monitored by serial numbers. Any as found set pressure failure will be addressed via the CNS Corrective Action Program.ASME OM Code Interpretation, 98-8, clarifies that a pilot operated relief valve with an auxiliary actuating device is not required to be tested as a unit. Furthermore, it clarifies that set pressure determination on the pilot operator may be performed after the pilot operator is removed from the valve body.
CNS plans to continue this approach into the fifth ten-year interval. However, refueling outage 27 (Fall/2012) was the last refueling outage under an 18-month cycle. CNS is now operating with 24-month cycles. With this in mind, the refurbishment of the entire valves will eventually align with a six year frequency, which is consistent with Code Case OMN-1 7. However, all eight of the pilot assemblies are being removed, tested and replaced with refurbished/recertified spare pilot assemblies every refueling outage, which means a full complement of the set pressure portion of the valves are being tested every refueling outage. Therefore, although this approach is very conservative, documenting acceptability of this approach is being pursued per this relief request.
NLS2015026 Attachment 2 Page 70 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)
Additionally, since 5-6 pilot assemblies, alone, are being replaced every outage (versus the entire valve), documenting acceptability of how portions of Appendix 1-33 10 are being satisfied is also being pursued per this relief request.
Appendix I, 1-3310(a) visual examination is completed at the test facility for those main bodies and pilot assemblies being sent there for examination, testing and refurbishment.
: 5. Proposed Alternative and Basis for Use These eight SRVs are considered Class 1 main steam pressure relief valves with auxiliary actuating devices. They are located on the main steam lines. In addition to their automatic function of opening to prevent over pressurization of the reactor vessel, six of these valves are associated with the Automatic Depressurization System and two are associated with the Low Low Set logic. The valves are two-stage Target Rock valves, each equipped with a main body, a pilot assembly for set pressure control, a solenoid valve, and an air operator assembly.
With the removal of the pilot assemblies from the main bodies at the plant, the accessible portions of the main bodies will be examined in place without further disassembly as permitted by 1-1310(c).
CNS proposes to follow the Code Case OMN-17, paragraph (d), recommendations for Maintenance on these eight valves. Therefore, on a three cycle (up to 6 year) frequency, CNS proposes to remove the entire valve unit (i.e. main body and pilot assembly) for each one of these valves and ship it off for as found testing, refurbishment, and re-certification. CNS will replace these entire valve units with spare refurbished and re-certified entire valve units.
Appendix I, 1-3310(b) seat tightness, and 1-3310(c) set pressure, is satisfied through as found seat leakage and set pressure testing at the offsite test facility for those main valves and pilot valve assemblies being sent there for inspection, testing and refurbishment.
As mentioned earlier, each valve is equipped with a pilot valve assembly that controls the set pressure. The remainder of the pilot valve assemblies (5 or 6 per refueling outage) will be removed from the main body and sent off site for examination, as found testing, refurbishment, and re-qualification testing (set point, reseat, and pilot stage seat tightness). The test facility has a main body slave for this purpose. The removed pilot valve assemblies are replaced with previously refurbished and re-qualified pilot valve assemblies. By testing all of the pilot valve assemblies every outage, the potential need to expand to test additional valves due to set pressure failures is alleviated and the future valve reliability is improved. Test results are being monitored by serial numbers. Any as found set pressure failure will be addressed via the CNS Corrective Action Program.
Paragraph 1-3310(i) is satisfied through as left seat leakage testing at the facility.
ASME OM Code Interpretation, 98-8, clarifies that a pilot operated relief valve with an auxiliary actuating device is not required to be tested as a unit. Furthermore, it clarifies that set pressure determination on the pilot operator may be performed after the pilot operator is removed from the valve body.
Seat leakage of installed main valves is continuously monitored and also satisfies 1-3310(i).
 
Pressure switches in the SRV discharge lines annunciate in the control room and indicate when the main valve seat is open. In addition, there are temperature elements on the valve discharge lines which provide leakage indication.
NLS2015026 Page 70 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)
During startup, the main valve and Auxiliary Actuation Devices are verified to function properly by being full stroke exercised open and closed. Successfully exercising these valves open and closed verifies the electrical characteristics and pressure integrity of the solenoid valve and air actuator (satisfying Appendix I, paragraphs (d) and (e)). During this exercise, Appendix I, paragraph 1-3310(f), is also satisfied through the use of the valve indicating lights, discharge pressure switches, and temperature elements.Finally, Appendix I, paragraphs 1-3310(g) and 1-3310(h), are not applicable to the CNS MS safety relief valves.This proposed alternative is conservative in nature and will continue to provide an acceptable level of quality and safety pursuant to 10 CFR 50.55a(h)(3)(z)(1).
Appendix I, 1-3310(a) visual examination is completed at the test facility for those main bodies and pilot assemblies being sent there for examination, testing and refurbishment. With the removal of the pilot assemblies from the main bodies at the plant, the accessible portions of the main bodies will be examined in place without further disassembly as permitted by 1-1310(c).
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RV-04 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
Appendix I, 1-3310(b) seat tightness, and 1-3310(c) set pressure, is satisfied through as found seat leakage and set pressure testing at the offsite test facility for those main valves and pilot valve assemblies being sent there for inspection, testing and refurbishment. Paragraph 1-3310(i) is satisfied through as left seat leakage testing at the facility. Seat leakage of installed main valves is continuously monitored and also satisfies 1-3310(i). Pressure switches in the SRV discharge lines annunciate in the control room and indicate when the main valve seat is open. In addition, there are temperature elements on the valve discharge lines which provide leakage indication.
NLS2015026 Attachment 2 Page 71 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
During startup, the main valve and Auxiliary Actuation Devices are verified to function properly by being full stroke exercised open and closed. Successfully exercising these valves open and closed verifies the electrical characteristics and pressure integrity of the solenoid valve and air actuator (satisfying Appendix I, paragraphs (d) and (e)). During this exercise, Appendix I, paragraph 1-3310(f), is also satisfied through the use of the valve indicating lights, discharge pressure switches, and temperature elements.
Alternative Provides Acceptable Level of Quality and Safety 1. ASME Code Component(s)
Finally, Appendix I, paragraphs 1-3310(g) and 1-3310(h), are not applicable to the CNS MS safety relief valves.
Affected Valve Class Category System CRD-SOV-SO120*
This proposed alternative is conservative in nature and will continue to provide an acceptable level of quality and safety pursuant to 10 CFR 50.55a(h)(3)(z)(1).
2 B CRD CRD-SOV-SO121*
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
2 B CRD CRD-SOV-SO122*
: 7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RV-04 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).
2 B CRD CRD-SOV-SO123*
 
2 B CRD CRD-AOV-CV126*
NLS2015026 Page 71 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)
2 B CRD CRD-AOV-CV127*
Alternative Provides Acceptable Level of Quality and Safety
2 B CRD CRD-CV-114CV*
: 1.     ASME Code Component(s) Affected Valve                   Class           Category                 System CRD-SOV-SO120*                       2                 B                     CRD CRD-SOV-SO121*                       2                 B                     CRD CRD-SOV-SO122*                       2                 B                     CRD CRD-SOV-SO123*                       2                 B                     CRD CRD-AOV-CV126*                       2                 B                     CRD CRD-AOV-CV127*                       2                 B                     CRD CRD-CV-114CV*                         2                 C                     CRD CRD-CV-138CV*                         2                 C                     CRD SOV=Solenoid Operated Valve AOV=Air Operated Valve CV=Check Valve
2 C CRD CRD-CV-138CV*
              *Typical of 137 Hydraulic Control Units (HCU)
2 C CRD SOV=Solenoid Operated Valve AOV=Air Operated Valve CV=Check Valve*Typical of 137 Hydraulic Control Units (HCU)2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda 3. Applicable Code Requirement ASME OM Code ISTC-3500 Valve Testing Requirements  
: 2.     Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
-Active and passive valves in the categories defined in ISTC-1300 shall be tested in accordance with the paragraphs specified in Table ISTC-3500-1 and the applicable requirements of ISTC-5 100 and ISTC-5200.
: 3.     Applicable Code Requirement ASME OM Code ISTC-3500 Valve Testing Requirements - Active and passive valves in the categories defined in ISTC-1300 shall be tested in accordance with the paragraphs specified in Table ISTC-3500-1 and the applicable requirements of ISTC-5 100 and ISTC-5200.
ISTC-3510 Exercising Test Frequency  
ISTC-3510 Exercising Test Frequency - Active Category A, Category B, and Category C check valves shall be exercised nominally every three (3) months, except as provided by ISTC-3520, ISTC-3540, ISTC-3550, ISTC-3570, ISTC-5221, and ISTC-5222.
-Active Category A, Category B, and Category C check valves shall be exercised nominally every three (3) months, except as provided by ISTC-3520, ISTC-3540, ISTC-3550, ISTC-3570, ISTC-5221, and ISTC-5222.
ISTC-3560 Fail-Safe Valves - Valves with fail-safe actuators shall be tested by observing the operation of the actuator upon loss of valve actuating power in accordance with the exercising frequency of ISTC-35 10.
ISTC-3560 Fail-Safe Valves -Valves with fail-safe actuators shall be tested by observing the operation of the actuator upon loss of valve actuating power in accordance with the exercising frequency of ISTC-35 10.ISTC-5131 (a) Valve Stroke Testing -Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.
ISTC-5131 (a) Valve Stroke Testing - Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.
ISTC-5151 (a) Valve Stroke Testing -Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.
ISTC-5151 (a) Valve Stroke Testing - Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.
NLS2015026 Attachment 2 Page 72 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing (continued)
 
ISTC-5221 (a) Valve Obturator Movement -The necessary valve obturator movement during exercise testing shall be demonstrated by performing both an open and a close test.4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(l), relief is requested from the requirements of ASME OM Code ISTC-3500, ISTC-35 10, ISTC-3560, ISTC-5131 (a), ISTC-5151 (a), and ISTC-5221 (a). The proposed alternative would provide an acceptable level of quality and safety.This relief is needed to make the fifth ten-year inservice test program consistent with NUREG 1482, Revision 2.5. Proposed Alternative and Basis for Use Background Information It is typical for Boiling Water Reactors (BWR) to perform the subject CRD testing per their respective plant Technical Specifications.
NLS2015026 Page 72 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing (continued)
This originated from Generic Letter (GL) 89-04, Position 7. Per section 1.3 of NUREG 1482, Revision 2, specific relief is required to implement the guidance derived from GL 89-04, which is why this testing is being documented under a relief request. The proposed alternatives and the basis for use are discussed in further detail below.CRD-CV-138CV; CRD-SOV-SO120, SO121, S0122, SO123: The CRD cooling water header check valve, CRD-CV-I 38CV (typical of 137 HCUs), has a safety function to close in the event of a scram to prevent diversion of pressurized HCU accumulator water to the cooling water header. The exhaust water withdrawal/settle (CRD-SOV-SO 120), exhaust water insert (CRD-SOV-SO 121), drive water withdrawal (CRD-SOV-SO 122), and drive water insert (CRD-SOV-SO 123) solenoid valves (typical of 137), have a safety function to close in order to provide a boundary to non-code class piping.Normal control rod motion will verify that the associated cooling water check valve has moved to its safety function position of closed. Industry experience has shown that rod motion may not occur if this check valve were to fail in the open position.The solenoid valves listed above have a safety function to close in order to provide a class 2 to non-code class boundary isolation.
ISTC-5221 (a) Valve Obturator Movement - The necessary valve obturator movement during exercise testing shall be demonstrated by performing both an open and a close test.
During normal operation, these solenoid valves are used for control rod insertion and withdrawal.
: 4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(l), relief is requested from the requirements of ASME OM Code ISTC-3500, ISTC-35 10, ISTC-3560, ISTC-5131 (a),
They are exercised open and closed during normal operation of the associated CRD. They are not equipped with position indication or control switches.
ISTC-5151 (a), and ISTC-5221 (a). The proposed alternative would provide an acceptable level of quality and safety.
They automatically change position to affect control rod movement.Therefore, control rod exercising in accordance with the CNS Technical Specifications, Surveillance Requirement (SR) 3.1.3.3, will provide an acceptable level of quality and safety for these valves. This testing method is consistent with GL 89-04, Position 7, and NUREG 1482, Revision 2, Section 4.4.6.
This relief is needed to make the fifth ten-year inservice test program consistent with NUREG 1482, Revision 2.
NLS2015026 Attachment 2 Page 73 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing (continued)
: 5. Proposed Alternative and Basis for Use Background Information It is typical for Boiling Water Reactors (BWR) to perform the subject CRD testing per their respective plant Technical Specifications. This originated from Generic Letter (GL) 89-04, Position 7. Per section 1.3 of NUREG 1482, Revision 2, specific relief is required to implement the guidance derived from GL 89-04, which is why this testing is being documented under a relief request. The proposed alternatives and the basis for use are discussed in further detail below.
CRD-AOV-CV 126, CRD-AOV-CV 127, and CRD-CV- 114CV: These valves operate as an integral part of their respective HCU to rapidly insert the control rods in support of a scram. The CRD scram inlet valve, CRD-AOV-CV126 (typical of 137), opens with a scram signal to pressurize the lower side of the Control Rod Drive Mechanism (CRDM)pistons from the accumulator or from the charging water header. The CRD outlet isolation valve, CRD-AOV-CV 127 (typical of 137), opens with scram signal to vent the top of the CRDM piston to the scram discharge header. The CRD scram outlet check valve, CRD-CV-1 14CV (typical of 137), opens to allow flow from the top of the CRDM piston to the scram discharge header.Individual stroke time measurements of air-operated valves CRD-AOV-CVI126 and CRD-AOV-CV 127 are impractical due to their rapid acting operation and they are not equipped with position indication.
CRD-CV-138CV; CRD-SOV-SO120, SO121, S0122, SO123:
Therefore, valve stroke times will not be measured.
The CRD cooling water header check valve, CRD-CV-I 38CV (typical of 137 HCUs), has a safety function to close in the event of a scram to prevent diversion of pressurized HCU accumulator water to the cooling water header. The exhaust water withdrawal/settle (CRD-SOV-SO 120), exhaust water insert (CRD-SOV-SO 121), drive water withdrawal (CRD-SOV-SO 122),
Additionally, the air-operated valves fail-open on a loss of air or power. Normal opening removes power to the pilot solenoid valve, simulating a loss of power. On loss of power, the solenoid vents the air operator and CRD-AOV-CV 126 and CRD-AOV-CV 127 are spring-driven open. Thus, each time a scram signal is given, the valves "experience" a loss of air/power to verify each valve's fail-safe open feature.Testing these valves simultaneously would result in a full reactor scram. An excess number of scrams performed routinely could cause thermal and reactivity transients, which could lead to fuel, vessel, CRD, or piping damage. The CRDs cannot be tested during cold shutdown because the control rods are inserted and must remain inserted.Therefore, control rod scram time testing in accordance with the CNS Technical Specifications, SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4, will provide an acceptable level of quality and safety for these valves. This testing method for these valves is consistent with GL 89-04, Position 7, and NUREG 1482, Revision 2, Section 4.4.6.6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as relief request RV-06 (TAC No. ME1521, April 26, 2010). A similar alternative was approved at Perry-1 for relief request VR-1, revision 1 (TAC No. ME7380, February 22, 2012).
and drive water insert (CRD-SOV-SO 123) solenoid valves (typical of 137), have a safety function to close in order to provide a boundary to non-code class piping.
NLS2015026 Attachment 2 Page 74 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests Proposed Alternative in Accordance with 10 CFR 50.55a(h)(z)(3)(1)
Normal control rod motion will verify that the associated cooling water check valve has moved to its safety function position of closed. Industry experience has shown that rod motion may not occur if this check valve were to fail in the open position.
Alternative Provides Acceptable Level of Quality and Safety 1. ASME Code Component(s)
The solenoid valves listed above have a safety function to close in order to provide a class 2 to non-code class boundary isolation. During normal operation, these solenoid valves are used for control rod insertion and withdrawal. They are exercised open and closed during normal operation of the associated CRD. They are not equipped with position indication or control switches. They automatically change position to affect control rod movement.
Affected Valve Class Category System RHR-MOV-MO25A 1 A RHR RHR-MOV-MO25B 1 A RHR RHR-MOV-MO274A I A RHR RHR-MOV-MO274B 1 A RHR RHR-CV-26CV I A/C RHR RHR-CV-27CV 1 A/C RHR RHR-MOV-MO17 1 A RHR RHR-MOV-MO18 1 A RHR CS-MOV-MO 12A I A CS CS-MOV-MO12B 1 A CS CS-CV-18CV 1 A/C CS CS-CV-19CV 1 A/C CS MOV=Motor Operated Valve 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda 3. Applicable Code Requirement ISTC-3630  
Therefore, control rod exercising in accordance with the CNS Technical Specifications, Surveillance Requirement (SR) 3.1.3.3, will provide an acceptable level of quality and safety for these valves. This testing method is consistent with GL 89-04, Position 7, and NUREG 1482, Revision 2, Section 4.4.6.
-Leakage Rate for Other Than Containment Isolation Valves.ISTC-3630(a)  
 
-Frequency.
NLS2015026 Page 73 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing (continued)
Tests shall be conducted at least once every two years.4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTC-3630(a).
CRD-AOV-CV 126, CRD-AOV-CV 127, and CRD-CV- 114CV:
ISTC-3630(a) requires that leakage rate testing (water) for pressure isolation valves (PIV) be performed at least once every two years.Data from RE25 and RE26 was used to identify that PIV testing alone each refueling outage incurs a total dose of at least 600 mRem. The reason for this relief request is to reduce outage dose. The basis of this relief request is that the proposed alternative would provide an acceptable level of quality and safety.5. Proposed Alternative and Basis for Use The RHR and CS systems at CNS contain valves that function as PIVs. PIVs are defined as two normally closed valves in series at the reactor coolant system boundary that isolate the reactor NLS2015026 Attachment 2 Page 75 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued) coolant system from an attached low pressure system. These affected valves, listed in Section 1, are located on the 'A' and 'B' CS and RHR injection lines and the RHR shutdown cooling line.PIVs are not specifically included in the scope for performance-based testing as provided for in 10 CFR 50 Appendix J, Option B. The concept behind the Option B alternative for containment isolation valves is that licensees should be allowed to adopt cost effective methods for complying with regulatory requirements.
These valves operate as an integral part of their respective HCU to rapidly insert the control rods in support of a scram. The CRD scram inlet valve, CRD-AOV-CV126 (typical of 137), opens with a scram signal to pressurize the lower side of the Control Rod Drive Mechanism (CRDM) pistons from the accumulator or from the charging water header. The CRD outlet isolation valve, CRD-AOV-CV 127 (typical of 137), opens with scram signal to vent the top of the CRDM piston to the scram discharge header. The CRD scram outlet check valve, CRD-CV-1 14CV (typical of 137), opens to allow flow from the top of the CRDM piston to the scram discharge header.
Additionally, NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," describes the risk-informed basis for the extended test intervals under Option B. That justification shows that for valves which have demonstrated good performance by passing their leak rate tests (air) for two consecutive cycles, further failures appear to be governed by the random failure rate of the component.
Individual stroke time measurements of air-operated valves CRD-AOV-CVI126 and CRD-AOV-CV 127 are impractical due to their rapid acting operation and they are not equipped with position indication. Therefore, valve stroke times will not be measured. Additionally, the air-operated valves fail-open on a loss of air or power. Normal opening removes power to the pilot solenoid valve, simulating a loss of power. On loss of power, the solenoid vents the air operator and CRD-AOV-CV 126 and CRD-AOV-CV 127 are spring-driven open. Thus, each time a scram signal is given, the valves "experience" a loss of air/power to verify each valve's fail-safe open feature.
NEI 94-01 also presents the results of a comprehensive risk analysis, including the statement that "the risk impact associated with increasing  
Testing these valves simultaneously would result in a full reactor scram. An excess number of scrams performed routinely could cause thermal and reactivity transients, which could lead to fuel, vessel, CRD, or piping damage. The CRDs cannot be tested during cold shutdown because the control rods are inserted and must remain inserted.
[leakrate]
Therefore, control rod scram time testing in accordance with the CNS Technical Specifications, SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4, will provide an acceptable level of quality and safety for these valves. This testing method for these valves is consistent with GL 89-04, Position 7, and NUREG 1482, Revision 2, Section 4.4.6.
test intervals is negligible (less than 0.1 percent of total risk)." The valves identified in this relief request are in water applications.
: 6.     Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
The PIV testing is performed with water pressurized to normal plant operating pressures.
: 7.     Precedents This relief request was previously approved for the fourth ten-year interval at CNS as relief request RV-06 (TAC No. ME1521, April 26, 2010). A similar alternative was approved at Perry-1 for relief request VR-1, revision 1 (TAC No. ME7380, February 22, 2012).
This relief request is intended to provide for a performance-based scheduling of PIV tests at CNS.As stated in the previous section, the reason for requesting this relief is dose reduction.
 
Data reviewed from RE25 and RE26 identified that PIV testing alone incurred a total dose of approximately 600 mrem in RE26, which benefited from the chemical decontamination that was performed, and approximately 1600 mrem in RE25. Therefore, assuming the PIVs remain classified as good performers, extended test intervals of three refueling outages would provide a savings of at least 1200 mrem over a three-cycle period.NUREG 0933, "Resolution of Generic Safety Issues," Issue 105, discusses the need for PIV leak rate testing based primarily on three pre-1980 historical failures of applicable valves industry-wide. These failures involved human errors in either operations or maintenance.
NLS2015026 Page 74 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests Proposed Alternative in Accordance with 10 CFR 50.55a(h)(z)(3)(1)
None of these failures involved inservice equipment degradation.
Alternative Provides Acceptable Level of Quality and Safety
The performance of PIV leak rate testing provides assurance of acceptable seat leakage with the valve in a closed condition.
: 1.     ASME Code Component(s) Affected Valve               Class             Category                 System RHR-MOV-MO25A                   1                 A                       RHR RHR-MOV-MO25B                   1                 A                       RHR RHR-MOV-MO274A                   I                 A                       RHR RHR-MOV-MO274B                   1                 A                       RHR RHR-CV-26CV                 I               A/C                     RHR RHR-CV-27CV                 1               A/C                     RHR RHR-MOV-MO17                   1                 A                       RHR RHR-MOV-MO18                   1                 A                       RHR CS-MOV-MO 12A                 I                 A                       CS CS-MOV-MO12B                   1                 A                       CS CS-CV-18CV                 1               A/C                       CS CS-CV-19CV                 1               A/C                       CS MOV=Motor Operated Valve
Typical PIV testing does not identify functional problems which may inhibit the valves ability to re-position from open to closed. For check valves, such functional testing is accomplished per ASME OM Code ISTC-3522 and ISTC-3520.
: 2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
Power-operated valves are routinely full stroke tested per ASME OM Code to ensure their functional capabilities.
: 3. Applicable Code Requirement ISTC-3630 - Leakage Rate for Other Than Containment Isolation Valves.
The periodic functional testing of the PIVs is adequate to identify abnormal conditions that might affect closure capability.
ISTC-3630(a) - Frequency. Tests shall be conducted at least once every two years.
: 4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTC-3630(a). ISTC-3630(a) requires that leakage rate testing (water) for pressure isolation valves (PIV) be performed at least once every two years.
Data from RE25 and RE26 was used to identify that PIV testing alone each refueling outage incurs a total dose of at least 600 mRem. The reason for this relief request is to reduce outage dose. The basis of this relief request is that the proposed alternative would provide an acceptable level of quality and safety.
: 5. Proposed Alternative and Basis for Use The RHR and CS systems at CNS contain valves that function as PIVs. PIVs are defined as two normally closed valves in series at the reactor coolant system boundary that isolate the reactor
 
NLS2015026 Page 75 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued) coolant system from an attached low pressure system. These affected valves, listed in Section 1, are located on the 'A' and 'B' CS and RHR injection lines and the RHR shutdown cooling line.
PIVs are not specifically included in the scope for performance-based testing as provided for in 10 CFR 50 Appendix J, Option B. The concept behind the Option B alternative for containment isolation valves is that licensees should be allowed to adopt cost effective methods for complying with regulatory requirements. Additionally, NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," describes the risk-informed basis for the extended test intervals under Option B. That justification shows that for valves which have demonstrated good performance by passing their leak rate tests (air) for two consecutive cycles, further failures appear to be governed by the random failure rate of the component. NEI 94-01 also presents the results of a comprehensive risk analysis, including the statement that "the risk impact associated with increasing [leakrate] test intervals is negligible (less than 0.1 percent of total risk)." The valves identified in this relief request are in water applications. The PIV testing is performed with water pressurized to normal plant operating pressures. This relief request is intended to provide for a performance-based scheduling of PIV tests at CNS.
As stated in the previous section, the reason for requesting this relief is dose reduction. Data reviewed from RE25 and RE26 identified that PIV testing alone incurred a total dose of approximately 600 mrem in RE26, which benefited from the chemical decontamination that was performed, and approximately 1600 mrem in RE25. Therefore, assuming the PIVs remain classified as good performers, extended test intervals of three refueling outages would provide a savings of at least 1200 mrem over a three-cycle period.
NUREG 0933, "Resolution of Generic Safety Issues," Issue 105, discusses the need for PIV leak rate testing based primarily on three pre-1980 historical failures of applicable valves industry-wide. These failures involved human errors in either operations or maintenance. None of these failures involved inservice equipment degradation. The performance of PIV leak rate testing provides assurance of acceptable seat leakage with the valve in a closed condition. Typical PIV testing does not identify functional problems which may inhibit the valves ability to re-position from open to closed. For check valves, such functional testing is accomplished per ASME OM Code ISTC-3522 and ISTC-3520. Power-operated valves are routinely full stroke tested per ASME OM Code to ensure their functional capabilities. The periodic functional testing of the PIVs is adequate to identify abnormal conditions that might affect closure capability.
Performance of the separate 24-month PIV leak rate testing does not contribute any additional assurance of functional capability; it only determines the seat tightness of the closed valves.
Performance of the separate 24-month PIV leak rate testing does not contribute any additional assurance of functional capability; it only determines the seat tightness of the closed valves.
NLS2015026 Attachment 2 Page 76 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)
 
The functional test and position indication test (PIT) frequencies are as follows: Valve Functional Test PIT RHR-MOV-MO25A Quarterly 2 years RHR-MOV-MO25B Quarterly 2 years RHR-MOV-MO274A Normally De-energized Closed Refueling Outage (exercised during PIT test)RHR-MOV-MO274B Normally De-energized Closed Refueling Outage (exercised during PIT test)RHR-CV-26CV Refueling Outage Refueling Outage RHR-CV-27CV Refueling Outage Refueling Outage RHR-MOV-MO17 Cold S/D Refueling Outage RHR-MOV-MO 18 Cold S/D Refueling Outage CS-MOV-MO 12A Cold S/D Refueling Outage CS-MOV-MO 12B Cold S/D Refueling Outage CS-CV-18CV Refueling Outage Refueling Outage CS-CV-19CV Refueling Outage Refueling Outage CNS proposes to perform PIV testing at intervals ranging from every refueling outage to every third refueling outage. The specific interval for each valve would be a function of its performance and would be established in a manner consistent with the containment isolation valve (CIV) process under 10 CFR 50 Appendix J, Option B. Five of the 12 valves listed in Section 1 (RHR-MOV-MO25A, RHR-MOV-MO25B, CS-MOV-MO12A, CS-MOV-MO12B, RHR-MOV-MO  
NLS2015026 Page 76 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)
: 17) are also classified as CIVs and are leak rate tested with air at intervals determined by 10 CFR 50 Appendix J, Option B. Appendix J and inservice leak testing program guidance will be established such that if any of those five valves fail either their as found CIV test or their PIV test, the test interval for both tests will be reduced to every refueling outage until they can be re-classified as good performers per Appendix J, Option B requirements.
The functional test and position indication test (PIT) frequencies are as follows:
The test intervals for the seven remaining valves with a PIV-only function will be determined in the same manner as is done under Option B. That is, the test interval may be extended to every three refueling outages (not to exceed a nominal six year period) upon completion of two consecutive, periodic PIV tests with results within prescribed acceptance criteria.
Valve                         Functional Test                       PIT RHR-MOV-MO25A                             Quarterly                       2 years RHR-MOV-MO25B                             Quarterly                       2 years RHR-MOV-MO274A               Normally De-energized Closed           Refueling Outage (exercised during PIT test)
Any test failure will require a return to the initial interval (every refueling outage) until good performance can again be established.
RHR-MOV-MO274B               Normally De-energized Closed           Refueling Outage (exercised during PIT test)
RHR-CV-26CV                     Refueling Outage               Refueling Outage RHR-CV-27CV                       Refueling Outage               Refueling Outage RHR-MOV-MO17                             Cold S/D                   Refueling Outage RHR-MOV-MO 18                           Cold S/D                   Refueling Outage CS-MOV-MO 12A                           Cold S/D                   Refueling Outage CS-MOV-MO 12B                           Cold S/D                   Refueling Outage CS-CV-18CV                     Refueling Outage               Refueling Outage CS-CV-19CV                     Refueling Outage               Refueling Outage CNS proposes to perform PIV testing at intervals ranging from every refueling outage to every third refueling outage. The specific interval for each valve would be a function of its performance and would be established in a manner consistent with the containment isolation valve (CIV) process under 10 CFR 50 Appendix J, Option B. Five of the 12 valves listed in Section 1 (RHR-MOV-MO25A, RHR-MOV-MO25B, CS-MOV-MO12A, CS-MOV-MO12B, RHR-MOV-MO 17) are also classified as CIVs and are leak rate tested with air at intervals determined by 10 CFR 50 Appendix J, Option B. Appendix J and inservice leak testing program guidance will be established such that if any of those five valves fail either their as found CIV test or their PIV test, the test interval for both tests will be reduced to every refueling outage until they can be re-classified as good performers per Appendix J, Option B requirements.
The test intervals for the seven remaining valves with a PIV-only function will be determined in the same manner as is done under Option B. That is, the test interval may be extended to every three refueling outages (not to exceed a nominal six year period) upon completion of two consecutive, periodic PIV tests with results within prescribed acceptance criteria. Any test failure will require a return to the initial interval (every refueling outage) until good performance can again be established.
The primary basis for this relief request is the historically good performance of the PIVs. There have been no PIV seat leakage failures since PIV testing began at CNS in 1995 through the present. Leakages recorded have been a very small percentage of the overall allowed leakage.
The primary basis for this relief request is the historically good performance of the PIVs. There have been no PIV seat leakage failures since PIV testing began at CNS in 1995 through the present. Leakages recorded have been a very small percentage of the overall allowed leakage.
NLS2015026 Attachment 2 Page 77 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)
 
The test results for the PIVs listed in Section 1 have been exceptional.
NLS2015026 Page 77 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)
For example, a plot of the RHR-MOV-
The test results for the PIVs listed in Section 1 have been exceptional. For example, a plot of the RHR-MOV-MO17 test results is shown below:
hWLeakap 2                                    $*Leekss2AIam La RHR.MOV-M017 PlV Test Dat 4.50 4.00 3,50 3.00
: a. 2.50 0
1.50 1.00 0.50 0.00                                                                            U 11MAM95        1201906        01M=              0        05 03110120=      041012011 Date This graph is typical of the affected PIVs listed in Section 1; however, there have been cases where the CIV air testing has indicated a failure with components identified in this relief request.
There is a general industry-wide consensus that CIV air testing is a more challenging and accurate measurement of seat condition, and more likely to identify any seat condition degradation. PIV testing has also been utilized at CNS as a post-maintenance test following packing replacements on the CS and RHR injection check valves to ensure the packing is adjusted adequately at normal system pressure. Therefore, PIV
: 5. Proposed Alternative and Basis for Use Code Case OMN-20 is included in the ASME OM Code, 2012 Edition, and will be used as an alternative to the frequencies of the ASME OM Code. The requirements of Code Case OMN-20 are described below.
: 5. Proposed Alternative and Basis for Use Code Case OMN-20 is included in the ASME OM Code, 2012 Edition, and will be used as an alternative to the frequencies of the ASME OM Code. The requirements of Code Case OMN-20 are described below.
NLS2015026 Attachment 2 Page 98 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)
 
ASME OM, Division 1, Section IST and all earlier editions and addenda specify component test frequencies based either on elapsed time periods (e.g., quarterly, 2 year, etc.) or the occurrence of plant conditions or events (e.g., cold shutdown, refueling outage, upon detection of a sample failure, following maintenance, etc.).(a) Components whose test frequencies are based on elapsed time periods shall be tested at the frequencies specified in Section IST with a specified time period between tests as shown in Table 1. The specified time period between tests may be reduced or extended as follows: (1) For periods specified as fewer than 2 years, the period may be extended by up to 25% for any given test.(2) For periods specified as greater than or equal to 2 years, the period may be extended by up to 6 months for any given test.(3) All periods specified may be reduced at the discretion of the owner (i.e., there is no minimum period requirement).
NLS2015026 Page 98 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)
Period extension is to facilitate test scheduling and considers plant operating conditions that may not be suitable for performance of the required testing (e.g., performance of the test would cause an unacceptable increase in the plant risk profile due to transient conditions or other ongoing surveillance, test, or maintenance activities).
ASME OM, Division 1, Section IST and all earlier editions and addenda specify component test frequencies based either on elapsed time periods (e.g., quarterly, 2 year, etc.) or the occurrence of plant conditions or events (e.g., cold shutdown, refueling outage, upon detection of a sample failure, following maintenance, etc.).
Period extensions are not intended to be used repeatedly merely as an operational convenience to extend test intervals beyond those specified.
(a) Components whose test frequencies are based on elapsed time periods shall be tested at the frequencies specified in Section IST with a specified time period between tests as shown in Table
Period extensions may also be applied to accelerated test frequencies (e.g., pumps in alert range)and other fewer than 2 year test frequencies not specified in Table 1.Period extensions may not be applied to the test frequency requirements specified in Subsection ISTD, Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants, as Subsection ISTD contains its own rules for period extensions.(b) Components whose test frequencies are based on the occurrence of plant conditions or events may not have their period between t ests extended except as allowed by ASME OM, Division 1, Section IST, 2009 Edition through OMa-20 11 Addenda and all earlier editions and addenda.
: 1. The specified time period between tests may be reduced or extended as follows:
NLS2015026 Attachment 2 Page 99 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)
(1) For periods specified as fewer than 2 years, the period may be extended by up to 25% for any given test.
Table 1 Specified Test Frequencies Frequency Specified Time Period Between Tests Quarterly 92 days (or every 3 months)Semiannually 184 days (or every 6 months)Annually (or every year) 366 days x years x calendar years where x is a whole number of years > 2 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.7. Precedents This relief request was previously approved for the Fermi-2 third ten-year interval as Relief Request PVRR-001 (TAC No. MF2967, dated July 16, 2014).Three Mile Island Nuclear Station, Unit 1 -Relief Requests PR-01, PR-02, and VR-02, Associated With The Fifth 10-Year Inservice Test Interval (TAC Nos. MF0046, MF0047 and MF0048, dated August 15, 2013).}}
(2) For periods specified as greater than or equal to 2 years, the period may be extended by up to 6 months for any given test.
(3) All periods specified may be reduced at the discretion of the owner (i.e., there is no minimum period requirement).
Period extension is to facilitate test scheduling and considers plant operating conditions that may not be suitable for performance of the required testing (e.g., performance of the test would cause an unacceptable increase in the plant risk profile due to transient conditions or other ongoing surveillance, test, or maintenance activities). Period extensions are not intended to be used repeatedly merely as an operational convenience to extend test intervals beyond those specified.
Period extensions may also be applied to accelerated test frequencies (e.g., pumps in alert range) and other fewer than 2 year test frequencies not specified in Table 1.
Period extensions may not be applied to the test frequency requirements specified in Subsection ISTD, Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants, as Subsection ISTD contains its own rules for period extensions.
(b) Components whose test frequencies are based on the occurrence of plant conditions or events may not have their period between t ests extended except as allowed by ASME OM, Division 1, Section IST, 2009 Edition through OMa-20 11 Addenda and all earlier editions and addenda.
 
NLS2015026 Page 99 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)
Table 1 Specified Test Frequencies Frequency                           Specified Time Period Between Tests Quarterly                                             92 days (or every 3 months)
Semiannually                                           184 days (or every 6 months)
Annually (or every year)                                         366 days x years                       x calendar years where x is a whole number of years > 2
: 6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
: 7. Precedents This relief request was previously approved for the Fermi-2 third ten-year interval as Relief Request PVRR-001 (TAC No. MF2967, dated July 16, 2014).
Three Mile Island Nuclear Station, Unit 1 - Relief Requests PR-01, PR-02, and VR-02, Associated With The Fifth 10-Year Inservice Test Interval (TAC Nos. MF0046, MF0047 and MF0048, dated August 15, 2013).}}

Latest revision as of 14:56, 19 March 2020

Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests
ML15084A221
Person / Time
Site: Cooper Entergy icon.png
Issue date: 03/19/2015
From: Limpias O
Nebraska Public Power District (NPPD)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NLS2015026
Download: ML15084A221 (103)
v • d • e


Text

N Nebraska Public Power District Always there when you need us 10 CFR 50.55a NLS2015026 March 19, 2015 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

Subject:

Fifth Ten-Year Interval Pump and Valve Inservice Testing Program Relief Requests Cooper Nuclear Station, Docket No. 50-298, License No. DPR-46

Dear Sir or Madam:

The purpose of this letter is for the Nebraska Public Power District (NPPD) to request that the Nuclear Regulatory Commission grant relief from certain Inservice Testing (IST) code requirements for the Cooper Nuclear Station (CNS) pursuant to 10 CFR 50.55a. The attached relief requests pertain to the American Society of Mechanical Engineers (ASME) Code for Operation and Maintenance (OM) of Nuclear Power Plants pump and valve testing requirements needed for the fifth ten-year IST interval, which commences on March 1, 2016. The applicable code for the fifth ten-year interval is the ASME OM Code 2004 Edition through the 2006 Addenda. NPPD requests approval of these relief requests by March 1, 2016, in support of the start of the fifth ten-year IST interval.

This update is for pumps, valves and snubbers. Relief requests previously approved for the fourth ten-year interval have been updated and are being resubmitted, as applicable, for the fifth ten-year interval code requirements. Relief Requests RP-08, RP-09, RV-02, and RG-01 are new relief requests. There are no relief requests being submitted for snubbers. CNS will use approved Code Case OMNN- 13 (2004 Edition), as listed in Table 1 of Regulatory Guide 1.192, Revision 1. Attachment 1 contains a summary listing of the changes for the fifth ten-year interval. Attachment 2 contains the fifth ten-year interval IST relief requests.

No formal licensee commitments are being made or modified by this submittal.

Should you have any questions concerning this matter, please contact Jim Shaw, Licensing Manager, at (402) 825-2788.

Sincer y, Vice President - Nuclear and Chief Nuclear Officer A 6 --

COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www.nppd.com

NLS2015026 Page 2 of 2

/dv Attachments 1. Cooper Nuclear Station Pump and Valve Inservice Testing Program Summary of Changes for the Fifth Ten-Year Interval 10 CFR 50.55a Relief Requests

2. Cooper Nuclear Station Pump and Valve Inservice Testing Program Fifth Ten-Year Interval 10 CFR 50.55a Relief Requests cc: Regional Administrator w/attachments USNRC - Region IV Senior Project Manager w/attachments USNRC - NRR Project Directorate IV-1 Senior Resident Inspector w/attachments USNRC - CNS NPG Distribution w/o attachments CNS Records w/attachments

NLS2015026 Page 1 of 2 Attachment 1 Cooper Nuclear Station Pump and Valve Inservice Testing Program Summary of Changes for the Fifth Ten-Year Interval 10 CFR 50.55a Relief Requests Relief Request (RP=Pump) Approved Fourth Ten-Year Interval Fifth Ten-Year Interval (RV=Valve) Relief Request (RG=General)

RP-01 Core Spray Pump Suction Gauge Updated American Society of Mechanical Range Requirements Engineers (ASME) Code references, 10 CFR 50.55a references, precedents.

RP-02 Residual Heat Removal Pump Updated ASME Code references, 10 CFR Suction Gauge Range Requirements 50.55a references, precedents.

RP-03 High Pressure Coolant Injection Updated ASME Code references, 10 CFR Pump Suction Gauge Range 50.55a references, precedents.

Requirements RP-04 Reactor Core Isolation Cooling Pump Updated ASME Code references, 10 CFR Suction Gauge Range Requirements 50.55a references, precedents.

RP-05 Loop Accuracy Requirements for Updated ASME Code references, 10 CFR Misc. Instruments 50.55a references, precedents.

RP-06 Reactor Equipment Cooling Pump Updated ASME Code references, 10 CFR Flow Rate Range Requirements 50.55a references, precedents.

RP-07 Core Spray Pump B Vibration Alert Updated ASME Code references, 10 CFR Limits 50.55a references, precedents, vibration value trends and D/P trend.

RP-08 N/A New Pump Relief Request for the Comprehensive Pump Test Upper Limit.

Proposed alternative is to use the 1.06 multiplier per ASME Operation and Maintenance (OM) Code Case OMN-19 in addition to incorporating a pump periodic verification test program.

RP-09 N/A New Pump Relief Request to incorporate an allowed variance around the reference values per ASME OM Code Case OMN-21.

RV-01 High Pressure Coolant Injection Revised to place more emphasis on the Solenoid Operated Drain Valve exercise test and to disassemble and examine Testing per the preventative maintenance program.

RV-02 N/A New Valve Relief Request for the Main Steam Safety Valve Testing per ASME OM Code Case OMN- 17 RV-03 N/A Main Steam Safety Relief Valve Testing. A version of this was previously approved per RV-04. Incorporated additional details on how these valves are being tested/refurbished.

NLS2015026 Page 2 of 2 Relief Request (RP=Pump) Approved Fourth Ten-Year Interval Fifth Ten-Year Interval (RV=Valve) Relief Request (RG-=General)

RV-04 Main Steam Power Operated Relief Control Rod Drive (CRD) Technical Valve Testing Specification Testing. Previously approved as RV-06. Updated ASME Code references, 10 CFR 50.55a references, precedents, and editorial changes, only.

RV-05 N/A Performance-Based Scheduling of Pressure Isolation Valve Tests. Previously approved as RV-07. Provided additional information to support the frequency extension supported by NEI 94-01, revision 3.

RV-06 Control Rod Drive (CRD) Technical N/A Specification Testing RV-07 Performance-Based Scheduling of N/A Pressure Isolation Valve Tests RG-01 N/A New Relief Request on ASME OM Code Test Frequencies grace period. Plan is to incorporate ASME OM Code Case OMN-20.

NLS2015026 Page 1 of 99 ATTACHMENT 2 Cooper Nuclear Station Pump and Valve Inservice Testing Program Fifth Ten-Year Interval 10 CFR 50.55a Relief Requests RELIEF REQUEST INDEX Relief Description Attachment 2 Request No. Page Number(s)

Pumps IF _ _

RP-01 Core Spray Pump Suction Gauge Range Requirements]I 2-4 RP-02 Residual Heat Removal Pump Suction Gauge Range 5-7 Requirements RP-03 High Pressure Coolant Injection Pump Suction Gauge 8-10 Range Requirements RP-04 Reactor Core Isolation Cooling Pump Suction Gauge 11-13 Range Requirements 11 IRP-05 Loop Accuracy Requirements 14-17 RP-06 Reactor Equipment Cooling Pump Flow Rate Gauge 18-19

[Range Requirements RP-07 Core Spray Pump B Vibration Alert Limits 20-54 RP-08 Comprehensive Pump Test Upper Limit 55-57 RP-09 Variance Around the Reference Values 58-59 Valves IRV-01 J[HPCI Solenoid Operated Drain Valve Testing ]I 60-62 RV-02 Main Steam Safety Valve Testing per Code Case 63-66 OMN-17 1RV-03 ((Main Steam Safety Relief Valve Testing 67-70 RV-04 Control Rod Drive (CRD) Technical Specification 71-73

_ Testing

_ I RV-05 [Performance-Based Scheduling of Pressure Isolation 74-95 1 Valve Leakage Tests General IF]

RG-01 ASME OM Code Test Frequencies IF 96-99

NLS2015026 Page 2 of 99 Relief Request RP-01 Core Spray Pump Suction Gauge Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected CS-P-ACore Spray Pump A CS-P-B Core Spray Pump B
2. Applicable Code Edition and Addenda American Society of Mechanical Engineers (ASME) Code for Operation and Maintenance of Nuclear Power Plants (OM Code) 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-3510(b)(1) - The full-scale range of each analog instrument shall not be greater than three times the reference value.
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB-35 10(b)(1). The proposed alternative would provide an acceptable level of quality and safety.

The installed suction pressure gauge range of the core spray pumps is 30" Hg (inches Mercury) to 30.0 pounds per square inch (psig). The actual values for suction pressure during inservice testing are approximately 4.0 psig. As a result, the instrument range exceeds the requirement of ISTB-3510(b)(1).

5. Proposed Alternative and Basis for Use Pump suction pressure is used along with pump discharge pressure to determine pump differential pressure. Pump suction pressure actual values for the core spray pumps during inservice testing are approximately 4.0 psig. Based on ISTB-3510(b)(1), this would require, as a maximum, a gauge with a range of 0 to 12.0 psig (3 X 4.0 psig) to bound the actual value for suction pressure.

Applying the accuracy requirement of +/- 2% of full scale (+/- 6% of reference) for the quarterly Group B pump test, the resulting inaccuracies due to pressure effects would be +/- 0.24 psig (0.02 X 12 psig).

Pump discharge pressure actual values for the core spray pumps during inservice testing are approximately 300 psig. Based on ISTB-3510(b)(1), this would require, as a maximum, a gauge with a range of 0 to 900 psig (3 X 300.0 psig) to bound the actual value for discharge pressure.

Applying the accuracy requirement of + 2% of full scale (+ 6% of reference) for the quarterly Group B pump test, the resulting inaccuracies due to pressure effects would be + 18 psig (0.02 X

NLS2015026 Page 3 of 99 Relief Request RP-01 Core Spray Pump Suction Gauge Range Requirements (Continued) 900 psig). Therefore, the maximum inaccuracies due to the suction and discharge pressure indications allowed by the code would be approximately +/- 18.24 psig.

The Cooper Nuclear Station (CNS) installed suction pressure gauges (PI-36A/B), which were designed to have an accuracy of +/- 0.5% of full scale, have a range of approximately 45 psig. The 45 psig gauge range is derived from the 30" Hg portion of the gauge range that is in a vacuum, which converts to approximately 15 psig, added to the 30 psig positive portion of the gauge. The

+/- 0.3 psig current calibration tolerance is essentially a tolerance of approximately 0.66% of full scale (0.0066 X 45 psig = - +/- 0.3 psig). Currently, the installed discharge pressure indicators (Pl-48A/B) are 0 to 500 psig indicators that are calibrated in a loop with corresponding pressure transmitters (PT-38A/B). These loops are being calibrated to +/- 10 psig, or + 2% of full scale (0.02 X 500 psig = + 10.0 psig).

As an alternative, for the Group B quarterly test, CNS will use the installed suction pressure gauge (30" Hg to 30.0 psig), currently calibrated to within a tolerance of+ 0.3 psig, together with the installed discharge pressure gauge (0 psig to 500 psig), currently calibrated in a loop to within a tolerance of+ 10 psig. This results in a combined maximum inaccuracy of+ 10.3 psig due to the installed suction and discharge pressure indications, which is less than the code-allowed

+ 18.24 psig.

Although the permanently installed suction pressure gauges (PI-36A/B) are above the maximum range limits of ASME OM Code ISTB-3510(b)(1), they, in conjunction with the permanently installed discharge pressure gauges (PI-48A/B), yield a better accuracy for differential pressure than the minimum requirements dictated by the code and are, therefore, suitable for the test. The range and accuracy of the instruments used to determine differential pressure will be within +/- 6%

of the differential pressure reference value. Reference NUREG 1482, Revision 2, Section 5.5.1.

Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval or actual suction and discharge pressure readings were to change significantly, this relief request will remain valid as long as the combination of range and accuracy will be less than the +/- 6% of the differential pressure reference value.

Using the provisions of this relief request as an alternative to the specific requirements of ISTB-351 0(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), Nebraska Public Power District (NPPD) requests relief from the specific ISTB requirements identified in this request.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.

NLS2015026 Page 4 of 99 Relief Request RP-01 Core Spray Pump Suction Gauge Range Requirements (Continued)

7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-01 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 5 of 99 Relief Request RP-02 Residual Heat Removal Pump Suction Gauge Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected RHR-P-A Residual Heat Removal (RHR) Pump A RHR-P-B Residual Heat Removal Pump B RHR-P-C Residual Heat Removal Pump C RHR-P-D Residual Heat Removal Pump D
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-35 I0(b)(1) - The full-scale range of each analog instrument shall not be greater than three times the reference value.
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB-3510(b)(1). The proposed alternative would provide an acceptable level of quality and safety.

The installed suction pressure gauge range of the residual heat removal pumps is 30" Hg to 150.0 psig. The actual values for suction pressure during inservice testing are approximately 5.0 psig. As a result, the instrument range exceeds the requirement of ISTB-3510(b)(1).

5. Proposed Alternative and Basis for Use Pump suction pressure is used along with pump discharge pressure to determine pump differential pressure. Pump suction actual values for the residual heat removal pumps during inservice testing is approximately 5.0 psig. Based on ISTB-3510(b)(1), this would require, as a maximum, a gauge with a range of 0 to 15.0 psig (3 X 5.0 psig) to bound the actual value for suction pressure. Applying the accuracy requirement of +/- 2% of full scale (+/- 6% of reference) for the quarterly Group A pump test, the resulting inaccuracies due to pressure effects would be +/- 0.3 psig (0.02 X 15.0 psig).

Pump discharge pressure actual values for the RHR pumps during inservice testing are approximately 170 to 195 psig. Conservatively basing it on the lowest of these discharge pressure readings, ISTB-3510(b)(1) would require, as a maximum, a gauge with a range of 0 to 510 psig (3 X 170.0 psig) to bound the actual value for discharge pressure.

NLS2015026 Page 6 of 99 Relief Request RP-02 Residual Heat Removal Pump Suction Gauge Range Requirements (Continued)

Applying the accuracy requirement of +/- 2% of full scale (+/- 6% of reference) for the quarterly Group A pump test, the resulting inaccuracies due to pressure effects would be +/- 10.2 psig (0.02 X 510 psig). Therefore, the maximum inaccuracies due to the suction and discharge pressure indications allowed by the code would be approximately +/- 10.5 psig.

The CNS-installed suction pressure gauges (PI-0I 6A/B/C/D), which were designed to have an accuracy of+/- 0.5% of full scale, have a range of approximately 165 psig. The 165 psig gauge range is derived from the 30" Hg portion of the gauge range that is in a vacuum, which converts to approximately 15 psig, added to the 150 psig positive portion of the gauge. The +/- 1.0 psig current calibration tolerance at the 5 psig suction pressure point is essentially a tolerance of approximately 0.6% of full scale (0.006 X 165 psig = -- +/- 1.0 psig). Currently, the installed discharge pressure indicators (PI-107A/B/C/D) are 0 to 400 psig indicators. The discharge indicators are being calibrated to +/- 5 psig, or +/- 1.25% of full scale (0.0 125 X 400 psig - + 5.0 psig).

As an alternative, for the Group A quarterly test, CNS will use the installed suction pressure gauge (30" Hg to 150.0 psig), currently calibrated to within a tolerance of 1 psig at the 5 psig point, together with the installed discharge pressure gauge (0 psig to 400 psig), currently calibrated to within a tolerance of +/- 5 psig. This results in a combined maximum inaccuracy of

+/- 6 psig due to the installed suction and discharge pressure indications, which is less than the code-allowed +/- 10.5 psig.

Although the permanently installed suction pressure gauges (PI-1 06A/B/C/D) are above the maximum range limits of ASME OM Code ISTB-3510(b)(1), they, in conjunction with the permanently installed discharge pressure gauges (PI-107A/B/C/D), yield a better accuracy for differential pressure than the minimum requirements dictated by the code and are, therefore, suitable for the test. The range and accuracy of the instruments used to determine differential pressure will be within +/- 6% of the differential pressure reference value. Reference NUREG 1482, "Guidelines for Inservice Testing at Nuclear Power Plants," Revision 2, Section 5.5.1.

Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval or actual suction and discharge pressure readings were to change significantly, this relief request will remain valid as long as the combination of range and accuracy will be less than the +/- 6% of the differential pressure reference value.

Using the provisions of this relief request as an alternative to the specific requirements of ISTB-35 10(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.

NLS2015026 Page 7 of 99 Relief Request RP-02 Residual Heat Removal Pump Suction Gauge Range Requirements (Continued)

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth 10-year interval.
7. Precedents This relief request was previously approved for the fourth 10-year interval at CNS as Relief Request RP-02 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 8 of 99 Relief Request RP-03 High Pressure Coolant Injection Pump Suction Gauge Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected HPCI-P-MP High Pressure Coolant Injection (HPCI) Main Pump HPCI-P-BP High Pressure Coolant Injection Booster Pump
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-35 10(b)(1) - The full-scale range of each analog instrument shall not be greater than three times the reference value.
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB -3510(b)(1). The proposed alternative would provide an acceptable level of quality and safety.

The installed suction pressure gauge range of the high pressure coolant injection pumps is 30" Hg to 150.0 psig. The actual value for suction pressure during inservice testing is approximately 15.0 psig. As a result, the instrument range exceeds the requirement of ISTB-3510(b)(1).

5. Proposed Alternative and Basis for Use Pump suction pressure is used along with pump discharge pressure to determine pump differential pressure. Pump suction actual values for the high pressure coolant injection pumps during inservice testing are approximately 15.0 psig. Based on ISTB-3510(b)(1) this would require, as a maximum, a gauge with a range of 0 to 45.0 psig (3 X 15.0 psig) to bound the actual value for suction pressure. Applying the accuracy requirement of+/- 2% of full scale (+ 6% of reference) for the quarterly Group B pump test, the resulting inaccuracies due to pressure effects would be

+/- 0.9 psig (0.02 X 45.0 psig).

The pump discharge pressure actual value for the HPCI pump during inservice testing is approximately 1200 psig. Based on ISTB-3510(b)(1), this would require, as a maximum, a gauge with a range of 0 to 3600 psig (3 X 1200.0 psig) to bound the actual value for discharge pressure.

Applying the accuracy requirement of +/- 2% of full scale (+/- 6% of reference) for the quarterly Group B pump test, the resulting inaccuracies due to pressure effects would be +/- 72 psig (0.02 X 3600 psig). Therefore, the maximum inaccuracies due to the suction and discharge pressure indications allowed by the code would be approximately +/- 72.9 psig.

NLS2015026 Page 9 of 99 Relief Request RP-03 High Pressure Coolant Injection Pump Suction Gauge Range Requirements (Continued)

The CNS-installed suction pressure gauge (PI-99), which was designed to have an accuracy of

+/- 0.5% of full scale, has a range of approximately 165 psig. The 165 psig gauge range is derived from the 30" Hg portion of the gauge range that is in a vacuum, which converts to approximately 15 psig, added to the 150 psig positive portion of the gauge. The +/- 1.0 psig current calibration tolerance is essentially a tolerance of approximately 0.6% of full scale (0.006 X 165 psig =

+/- 1.0 psig). Currently, the installed discharge pressure indicator (PI-81) is a 0 to 1500 psig indicator. The discharge indicator is currently being calibrated to +/- 7.5 psig, or +/- 0.5% of full scale (0.005 X 1500 psig = +/- 7.5 psig).

As an alternative, for the Group B quarterly test, CNS will use the installed suction pressure gauge (30" Hg to 150.0 psig), currently calibrated to within a tolerance of-+/- 1 psig, together with the installed discharge pressure gauge (0 psig to 1500 psig), currently calibrated to within a tolerance of+/- 7.5 psig. This results in a combined maximum inaccuracy of+/- 8.5 psig due to the installed suction and discharge pressure indications, which is less than the code-allowed +/- 72.9 psig.

Although the permanently installed suction pressure gauge (PI-99) is above the maximum range limits of ASME OM Code ISTB-3510(b)(1), it, in conjunction with the permanently installed discharge pressure gauge (PI-8 1), yields a better accuracy for differential pressure than the minimum requirements dictated by the code and is, therefore, suitable for the test. The range and accuracy of the instruments used to determine differential pressure will be within +/- 6% of the differential pressure reference value. Reference NUREG 1482, Revision 2, Section 5.5.1.

Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval or actual suction and discharge pressure readings were to change significantly, this relief request will remain valid as long as the combination of range and accuracy will be less than the +/- 6% of the differential pressure reference value.

Using the provisions of this relief request as an alternative to the specific requirements of ISTB-3510(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth 10-year interval.

NLS2015026 Page 10 of 99 Relief Request RP-03 High Pressure Coolant Injection Pump Suction Gauge Range Requirements (Continued)

7. Precedents This relief request was previously approved for the fourth 10-year interval at CNS as Relief Request RP-03 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 11 of 99 Relief Request RP-04 Reactor Core Isolation Cooling Pump Suction Gauge Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected RCIC-P-MP Reactor Core Isolation Cooling (RCIC) Main Pump
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-3510(b)(1) - The full-scale range of each analog instrument shall not be greater than three times the reference value.
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB-3510(b)(1). The proposed alternative would provide an acceptable level of quality and safety.

The installed suction pressure gauge range of the reactor core isolation cooling pump is 30" Hg to 150.0 psig. The actual value for suction pressure during inservice testing is approximately 15.0 psig. As a result, the instrument range exceeds the requirement of ISTB-3510(b)(1).

5. Proposed Alternative and Basis for Use Pump suction pressure is used along with pump discharge pressure to determine pump differential pressure. Pump suction actual values for the high pressure coolant injection pumps during inservice testing is approximately 15.0 psig. Based on ISTB-3510(b)(1) this would require, as a maximum, a gauge with a range of 0 to 45.0 psig (3 X 15.0 psig) to bound the lowest actual value for suction pressure. Applying the accuracy requirement of+/- 2% of full scale (+/- 6% of reference) for the quarterly Group B pump test, the resulting inaccuracies due to pressure effects would be +/- 0.9 psig (0.02 X 45.0 psig).

The discharge pressure actual value for the RCIC pump during inservice testing is approximately 1250 psig. Based on ISTB-3510(b)(1), this would require, as a maximum, a gauge with a range of 0 to 3750 psig (3 X 1250.0 psig) to bound the actual value for discharge pressure. Applying the accuracy requirement of +/- 2% of full scale (+/- 6% of reference) for the quarterly Group B pump test, the resulting inaccuracies due to pressure effects would be +/- 75 psig (0.02 X 3750 psig). Therefore, the maximum inaccuracies due to the suction and discharge pressure indications allowed by the code would be approximately + 75.9 psig.

NLS2015026 Page 12 of 99 Relief Request RP-04 Reactor Core Isolation Cooling Pump Suction Gauge Range Requirements (Continued)

The CNS-installed suction pressure gauge (PI-66), which was designed to have an accuracy of

+/- 0.5% of full scale, has a range of approximately 165 psig. The 165 psig gauge range is derived from the 30" Hg portion of the gauge range that is in a vacuum, which converts to approximately 15 psig, added to the 150 psig positive portion of the gauge. The +/- 1.0 psig current calibration tolerance is essentially a tolerance of approximately 0.6% of full scale (0.006 X 165 psig =

- +/- 1.0 psig). Currently, the installed discharge pressure indicator (PI-59) is a 0 to 1500 psig indicator. The discharge indicator is being calibrated to +/- 15 psig, or +/- 1.0% of full scale (0.01 X 1500 psig = +/- 15.0 psig).

As an alternative, for the Group B quarterly test, CNS will use the installed suction pressure gauge (30" Hg to 150.0 psig), currently calibrated to within a tolerance of +/- 1 psig, together with the installed discharge pressure gauge (0 psig to 1500 psig), currently calibrated to within a tolerance of+/- 15.0 psig. This results in a combined maximum inaccuracy of+/- 16.0 psig due to the installed suction and discharge pressure indications, which is less than the code-allowed

+/- 75.9 psig.

Although the permanently installed suction pressure gauge (PI-66) is above the maximum range limits of ASME OM Code ISTB-3510(b)(1), it, in conjunction with the permanently installed discharge pressure gauge (PI-59), yields a better accuracy for differential pressure than the minimum requirements dictated by the code and is, therefore, suitable for the test. The range and accuracy of the instruments used to determine differential pressure will be within +/- 6% of the differential pressure reference value. Reference NUREG 1482, Revision 2, Section 5.5.1.

Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval or actual suction and discharge pressure readings were to change significantly, this relief request will remain valid as long as the combination of range and accuracy will be less than the +/- 6% of the differential pressure reference value.

Using the provisions of this relief request as an alternative to the specific requirements of ISTB-351 0(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.

NLS2015026 Page 13 of 99 Relief Request RP-04 Reactor Core Isolation Cooling Pump Suction Gauge Range Requirements (Continued)

7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-04 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 14 of 99 Relief Request RP-05 Loop Accuracy Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternate Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected CS-P-A Core Spray (CS) Pump A CS-P-B Core Spray Pump B HPCI-P-MP High Pressure Coolant Injection Main Pump HPCI-P-BP High Pressure Coolant Injection Booster Pump RCIC-P-MP Reactor Core Isolation Cooling Pump SW-P-BPA Service Water Booster (SWB) Pump A SW-P-BPB Service Water Booster Pump B SW-P-BPC Service Water Booster Pump C SW-P-BPD Service Water Booster Pump D
2. Applicable Code Edition and Addenda ASME OM Code 2003 Edition through 2006 Addenda
3. Applicable Code Requirement Table ISTB-35 10-1, "Required Instrument Accuracy"
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB Table ISTB-3510-1 for Group A and B Pump Pressure accuracy (+/- 2%) and for flow rate accuracy (+/- 2%). The proposed alternative would provide an acceptable level of quality and safety.

The installed instrumentation for the subject pumps yield the following loop accuracies:

Pump Parameter Equip. Loop Calibration Loop Accuracy (%) Accuracy (%)

CS Pump Discharge Pressure 2.06 < 2.00%

CS Pump Flowrate 2.02 < 2.00%

HPCI Pump Flowrate 2.03 < 2.00%

RCIC Pump Flowrate 2.03 _<

2.00%

SWB Pump Flowrate 2.03 < 2.00%

As a result, the equipment loop accuracies do not meet the +/- 2% requirements of Table ISTB-35 10-1, "Required Instrument Accuracy."

NLS2015026 Page 15 of 99 Relief Request RP-05 Loop Accuracy Requirements (Continued)

5. Proposed Alternative and Basis for Use The difference between the code required and presently installed instrument loop accuracies is 0.06%, at a maximum, as presented above. This difference is insignificant when applied to the quantitative measured values for these parameters during the respective Group A or Group B quarterly tests. Additionally, all calibration tolerances of the loops involved meet or exceed the code-allowed accuracies of+/- 2% or better.

CS pump discharge pressure loop is made up of a pressure indicator (range of 0 to 500 psig) and a pressure transmitter. The pressure indicator (PI-48A/B) has a nameplate accuracy of +/- 2%, and the pressure transmitter (PT-38A/B) has a nameplate accuracy of+ 0.5%. Therefore, based on the nameplate accuracies alone, the equipment loop accuracy for discharge pressure indication is

+/- 2.06% (square root of the sum of the squares), which exceeds the code requirement of+/- 2%.

The variation from the code of 0.06%, with a gauge range of 0 to 500 psig, would amount to a potential deviation of only 0.3 psig (0.0006 X 500). However, CNS is currently calibrating this discharge pressure loop to within +/- 10 psig, which is equivalent to a +/- 2% of full scale tolerance (0.02 X 500 psig = +/- 10 psig), which meets the accuracy requirements of the code.

CS pump flow rate loop is made up of a flow indicator (range of 0 to 6000 gallons per minute

[gpm]), and a flow transmitter. The flow indicator (FI-50A/B) has a nameplate accuracy of+/- 2%,

and the flow transmitter (FT-40A/B) has a nameplate accuracy of+/- 0.25%. Therefore, based on the nameplate accuracies alone, the equipment loop accuracy for discharge pressure indication is

+/- 2.02% (square root of the sum of the squares), which exceeds the code requirement of+/- 2%.

The variation from the code of 0.02%, with a gauge range of 0 to 6000 gpm, would amount to potential deviation of only 1.2 gpm (6000 X .0002). However, CNS is currently calibrating this flow loop to within +/- 50 gpm (at the Inservice Testing (IST) reference value of 5000 gpm) or approximately + 0.83% of full scale (+/- 0.0083 X 6000 = - +/- 50 gpm), which is better than the

+/- 2% of full scale accuracy requirements of the code. If a preservice test were to be run, CNS would ensure that the loop was calibrated to < 2% over the full range of the test prior to performing it.

HPCI pump flow rate loop is made up of a flow indicating controller (range of 0 to 5000 gpm), a flow transmitter, and a flow square rooter. The flow indicating controller (FIC-108) has a nameplate accuracy of+/- 0.25%, the flow transmitter (FT-82) has a nameplate accuracy of

+/- 0.25%, and the flow square rooter (SQRT-1 18) has a nameplate accuracy of +/- 2% from approximately 0 to 1000 gpm and + 0.25% from approximately 1000 to 5000 gpm. Therefore, based on the nameplate accuracies alone, the equipment loop accuracy for flow indication is approximately +/- 2.03% (square root of the sum of the squares) from 0 to 1000 gpm, which does not meet the code requirement of +/- 2%, and approximately +/- 0.61% from 1000 to 5000 gpm, which does meet the code requirement of+/- 2%. The variation from the code of 0.03% in the range of 0 to 1000 gpm, with a gauge range of 0 to 5000 gpm, would amount to a potential deviation of only 1.5 gpm (5,000 X .0003). However, CNS is currently calibrating this flow loop to within +/- 100 gpm (at the IST reference of 4000 gpm and at other points from 1000 gpm to

NLS2015026 Page 16 of 99 Relief Request RP-05 Loop Accuracy Requirements (Continued) 5000 gpm) or approximately +/- 1.66% of full scale (+/- 0.0166 X 6000 = -+/- 100 gpm), which is better than the +/- 2% of full scale accuracy requirements of the code. If a preservice test were to be run, CNS would ensure that the loop was calibrated to < 2% over the full range of the test prior to performing it.

RCIC pump flow rate loop is made up of a flow indicating controller (range of 0 to 500 gpm), a flow transmitter, and a flow square rooter. The flow indicating controller (FIC-91) has a nameplate accuracy of+/- 2%, the flow transmitter (FT-58) has a nameplate accuracy of+/- 0.25%,

and the flow square rooter (SQRT-99) has a nameplate accuracy of +/- 2% from approximately 0 to 100 gpm and +/- 0.25% from approximately 100 to 500 gpm. Therefore, based on the nameplate accuracies alone, the equipment loop accuracy for flow indication is approximately + 2.03%

(square root of the sum of the squares) from 0 to 100 gpm, which does not meet the code requirement of+/- 2%, and approximately +/- 0.61% from 100 to 500 gpm, which does meet the code requirement of+ 2%. The variation from the code of 0.03% in the range of 0 to 100 gpm, with a gauge range of 0 to 500 gpm, would amount to a potential deviation of only 0.15 gpm (500 X .0003). However, CNS is currently calibrating this flow loop to within +/- 10 gpm over the entire range of flow or approximately + 1.66% of full scale (+ 0.0166 X 6000 = - +/- 100 gpm),

which is better than the +/- 2% of full scale accuracy requirements of the code.

The SWB flow rate is made up of a flow indicator (range of 0 to 10,000 gpm), a flow transmitter, and a flow square rooter. The flow indicator (FI-1 32A/B) has a nameplate accuracy of+/- 2%, the flow transmitter (FT-97) has a nameplate accuracy of+/- 0.25%, and the flow square rooter (SQRT-1 32) has a nameplate accuracy of+/- 0.25%. Therefore, based on the nameplate accuracies alone, the equipment loop accuracy for flow indication is approximately + 2.03% (square root of the sum of the squares), which exceeds the code requirement of +/- 2%. The variation from the code of 0.03%, with a gauge range of 0 to 10,000 gpm, would amount to a potential deviation of only 3 gpm (0.0003 X 10,000). However, CNS is currently calibrating this flow loop to within

+/- 100 gpm, which is equivalent to a +/- 1% of full scale tolerance (0.01 X 10,000 gpm = + 100 gpm), which is better than the +/- 2% of full scale accuracy requirements of the code.

As an alternative for the Group A or Group B quarterly test, CNS will use the installed instruments calibrated such that the loop accuracies are as indicated in the above table. No adjustments to acceptance criteria will be made as the calibrated loop accuracies will meet or exceed the code tolerances.

Although the permanently installed instrument loops do not meet the accuracy requirements of ASME OM Code ISTB Table ISTB-3510-1 when looking at nameplate accuracies, the effects of these small inaccuracies are insignificant when compared to the measured values, and credit will be taken for the ability to calibrate the loop within the code-allowed tolerance.

NLS2015026 Page 17 of 99 Relief Request RP-05 Loop Accuracy Requirements (Continued)

Although not anticipated, if any revisions to the current tolerance information provided occurs within the CNS fifth ten-year interval, this relief request will remain valid as long as the calibrated loop accuracies meet the code required tolerances of < 2.00% of full scale.

Using the provisions of this relief request as an alternative to the specific requirements of ISTB Table 3510-1, identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-05 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 18 of 99 Relief Request RP-06 Reactor Equipment Cooling Pump Flow Rate Range Requirements Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected REC-P-A Reactor Equipment Cooling (REC) Pump A REC-P-B Reactor Equipment Cooling Pump B REC-P-C Reactor Equipment Cooling Pump C REC-P-D Reactor Equipment Cooling Pump D
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-3510(b)(1) - The full-scale range of each analog instrument shall not be greater than three times the reference value.
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB-3510(b)(1). The proposed alternative would provide an acceptable level of quality and safety.

The installed flow rate instrument range of the reactor equipment cooling pumps is 0 to 4000 gpm. The reference values for flow rate during inservice testing are 1100 gpm. As a result, the instrument range exceeds the requirement of ISTB-35 10(b)(1).

5. Proposed Alternative and Basis for Use The permanent plant flow Instruments REC-FI-450A and REC-FI-450B are calibrated such that their accuracy is 1.25% of full scale. This yields a total inaccuracy of 50 gpm (0.0125 X 4000 gpm). Reference flow rates for the reactor equipment cooling pumps are 1100 gpm. Based on ISTB-3510(b)(1) this would require, as a maximum, a gauge with a range of 0 to 3300 gpm (3 X 1100 gpm) to bound the lowest reference value for flow.

Applying the accuracy requirement of +/- 2% for the pump test, the resulting inaccuracies due to flow would be + 66 gpm (0.02 X 3300 gpm).

NLS2015026 Page 19 of 99 Relief Request RP-06 Reactor Equipment Cooling Pump Flow Rate Range Requirements (Continued)

As an alternative, for the reactor equipment cooling pump inservice tests, CNS will use the installed flow rate instrumentation (0 to 4000 gpm) calibrated to less than +/- 2% such that the inaccuracies due to flow will be less than or equal to that required by the code (+/- 66 gpm). This will ensure that the installed flow rate instrumentation is equivalent to the code, or better, in terms of measuring flow rate.

Although the permanently installed flow gauges are above the maximum range limits of ASME OM Code ISTB-35 10(b)(1), they are within the accuracy requirements and are, therefore, suitable for the test. Reference NUREG 1482, Revision 2, Section 5.5.1.

Using the provisions of this relief request as an alternative to the specific requirements of ISTB-351 0(b)(1), identified above, will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTB requirements identified in this request.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-06 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 20 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected CS-P-B Core Spray Pump B
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB Table ISTB-5121-1, "Centrifugal Pump Test Acceptance Criteria"
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTB Table ISTB-5121-1 during the biennial comprehensive pump test or any other time vibrations are taken to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.). The proposed alternative would provide an acceptable level of quality and safety.

The IST Program has consistently required (prior to obtaining relief per RP-06 of the third interval program) that CS Pump B (CS-P-B) be tested on an increased frequency due to vibration values at Points 1H and 5H, as shown in Figure 1, periodically being in the alert range. Relief is requested from ISTB Table ISTB-5121-1 requirements to test the pump on an increased periodicity due to vibration levels for Points 1H and/or 5H exceeding the ISTB alert range absolute limit for the comprehensive pump test. This request is based on analysis of vibration and pump differential pressure data indicating that no pump degradation is taking place. CNS is proposing to use alternative vibration alert range limits for vibration Points 1H and 5H. This provides an alternative method that continues to meet the intended function of monitoring the pump for degradation over time while keeping the required action level unchanged.

5. Proposed Alternative and Basis for Use Pump Testing Methodology CS-P-B at CNS is tested using a full flow recirculation test line back to the suppression pool each quarter. CS-P-B has a minimum flow line which is used only to protect the pump from overheating when pumping against a closed discharge valve. The minimum flow line isolation valve for CS-P-B is initially open when the pump is started, and flow is initially recirculated through the minimum flow line back to the suppression pool.

NLS2015026 Page 21 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

Then, the full-flow test line isolation valve is throttled open to establish flow through the full-flow recirculation test line. The minimum flow line is then isolated automatically, and all flow remains through the full-flow test line for the IST test.

The B train of the CS system is operated in the same manner and under the same conditions for each test of CS-P-B, regardless of whether CNS is operating or shut down. Consequently, the pump will experience the same potential for flow-induced, low frequency vibration whenever it is tested, whether CNS is operating or shut down. As a result, this relief is requested for the comprehensive pump testing of CS-P-B when vibration measurements are required or any other time vibrations are recorded to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.).

CNS considers full-flow testing to be preferable to minimum flow testing due to the ability to evaluate overall pump performance at post-accident flow design conditions. Minimum flow testing would provide only limited information about the pump.

Nuclear Regulatory Commission (NRC) Staff Document NUREG/CP-0 152 NRC Staff document NUREG/CP-0 152, entitled "Proceedings of the Fourth NRC/ASME Symposium on Valve and Pump Testing," dated July 15-18, 1996, included a paper entitled Nuclear Power Plant Safety Related Pump Issues, by Joseph Colaccino of the NRC staff. That paper presented four key components that should be addressed in a relief request of this type to streamline the review process. These four key components are as follows:

I. The licensee should have sufficient vibration history from inservice testing which verifies that the pump has operated at this vibration level for a significant amount of time, with any "spikes" in the data justified.

II. The licensee should have consulted with the pump manufacturer or vibration expert about the level of vibration the pump is experiencing to determine if pump operation is acceptable.

III. The licensee should describe attempts to lower the vibration below the defined code absolute levels through modifications to the pump.

IV. The licensee should perform a spectral analysis of the pump-driver system to identify all contributors to the vibration levels.

The following is a discussion of how these four key components are addressed for this relief request.

NLS2015026 Page 22 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

I. Vibration History (Key Component No. 1)

A. Testing Methods and Code Requirements Inconsistent higher vibrations on CS-P-B have been a condition that has existed since original installation of this pump in 1973. During the construction and preoperational testing, vibrations were measured in "mils" at the top and side of the motor outboard (farthest from the pump), the side of the motor inboard (nearest the pump), and pump inboard (nearest the motor). The vibration signals were tape recorded along with the dynamic pressure pulsations in the suction and discharge of the pump as the flow was varied. The intention was to see if hydraulic disturbances were responsible for the observed phenomena. Observation of the vibration signals on the oscilloscope showed conclusively that the motor was vibrating with randomly distributed bursts of energy at the natural frequency of the total system. Therefore, it was determined that the hydraulic disturbances found in the piping was the source of the energy. Pipe restraints were added that reduced the piping system vibrations.

The monitoring of multiple vibration points over the years had not been a requirement of Section XI of the ASME Code until the adoption of the OM Standards/Codes. Therefore, at CNS, the first and second ten-year interval IST code requirements did not include the monitoring of multiple vibration points. The CNS second interval IST Program was committed to the 1980 Edition, Winter 1981 Addenda of Section XI. Paragraph IWP-4510 of this code required that "at least one displacement vibration amplitude shall be read during each inservice test." This code was in effect at CNS until the start of the third ten-year interval, which began on March 1, 1996. The CNS third interval IST Program was committed to the 1989 Edition of Section XI, which required multiple vibration points to be recorded during IST pump testing in accordance with the ANSI/ASME Operations and Maintenance Standard, Part 6, 1987 Edition with the 1988 Addenda.

However, CNS proactively began monitoring vibration on pumps in the IST Program in velocity units (inches per second) at multiple vibration points in 1990 in accordance with an approved relief request. Therefore, data exists for vibration Points 1H and 5H from April 1990 to the present. This data is included in the figures provided in this relief request. In April 1990, an analog velocity meter was utilized to begin measuring five different points in units of velocity. These are the same points measured today. Further technological advances resulted in the utilization of more reliable vibration meters beginning in late 1996. For the fourth interval, which began on March 1, 2006, the 2001 Edition through 2003 Addenda of the ASME OM Code was the code of record.

Vibration measurements were required to be taken only during the comprehensive test since the CS-P-B pump is considered a Group B pump. The same will be true for the fifth interval, beginning on March 1, 2016, in which the 2004 Edition through the 2006 Addenda of the ASME OM Code will be the code of record.

NLS2015026 Page 23 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

B. Review of Vibration History Data Beginning in April 1990, five vibration points (IV, 1H, 2H, 3H, 5H) were recorded for CS-P-B. However, the pump was tested at 4720 gpm from April 1990 to April 1992, then at 4800 gpm from April 1992 through December 1994, and finally at 5000 gpm from January 1995 to the present. The January 1995 test was also a post-maintenance test following the work that replaced the restricting orifice in the test return line. The last re-baseline occurred on November 6, 1996, due to the implementation of a new vibration meter with new instrument settings. Therefore, it would be appropriate to review the data from this date forward to track for degradation. This would be over eighteen years of data at the same reference points.

CS-P-B IST vibration trend graphs for vibration points 5H, IV, 2H, and 3H (Figures 3a, 4a, 5a, and 6a in this relief request), which include data from November 6, 1996, to the present, show flat or slightly downward trends. Vibration point 1H shows an essentially flat trend from -2002 to the present (Figure 2a) and when including the data since 1990 (Figure 2b). These observations indicate that CS-P-B vibrations are not increasing in magnitude. These trends also show that Points 1H and 5H occasionally exceed the alert range criteria (Figures 2a and 3a). Figure 12 illustrates the trend for CS-P-B differential pressure (D/P) readings from January 1995 (re-baselined pump at 5000 gpm) to the present. This represents approximately twenty years of data for pump D/P with the testing at 5000 gpm. As can be seen from Figure 12, no degradation in pump D/P has occurred.

Trend Graphs 2b, 3b, 4b, 5b, and 6b illustrate vibration data dating back to April 1990 for all vibration points. The data prior to 1996 represents data taken with analog, less reliable vibration instruments and, as discussed previously, at differing flows. However, it does clearly indicate that the piping-induced vibrations for vibration Points 1H and 5H were present in the early 1990s. This condition was also documented in the 1980s. In July 1985, CNS work item #85-2497 documented high vibration readings on the horizontal motor position. A pipe resonance problem was suspected at that time.

Vibrational readings varied between 0.3 and 0.5 in/sec with spikes to 0.7 in/sec every few seconds. This 1985 documentation, available vibration data since 1990, along with the testing performed during the preoperational time period, substantiates that the piping-induced vibrations have been in existence since the pump was installed. These graphs indicate that the vibration point trends since April 1990 are essentially flat or slightly downward. Therefore, based on the available data at CNS, this pump has experienced essentially no degradation in vibration levels for -24.5 years or in D/P for -20 years.

NLS2015026 Page 24 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

C. Review of "Spikes" in Vibration Data In reviewing the trend data for vibration points 1H (Figures 2a and 2b) and 5H (Figures 3a and 3b), which includes the code-required frequency ranges (one-third pump running speed to 1000 Hertz [Hz].), random spikes were observed throughout the data that resulted in values above the alert range. These spikes are best described in a 2001 report by Machinery Solutions, Inc., an industry expert on vibrations, as follows:

Most of the vibration that is measured on the motor casing is due to excitation of the structural resonances of the motor/pump by turbulent flow. These structural resonances are poorly damped and can be easily excited. Most vertical pumps have similar types of behavior, and it is not necessarily problematic by itself. A problem occurs when a pump has a continuous forcing function whose frequency coincides with a resonance (i.e., running speed). The forcing function in this case is flow turbulence caused in large part by the S-curve in the piping just off the pump discharge. The flow through this area generates lateral broadband forces, due to elbow effects, that excite the resonances in a non-continuous fashion.

This is why the amplitude swings so dramatically on the motor case (the location of vibration points 1H and 5H). The system goes from brief periods of excitation to brief periods of no excitation.

The discharge riser is also moving side to side from the same forces. Although the discharge piping configuration is both non-standard and less than optimum for this application, it poses no threat to the long-term reliability of either the pump or the motor. The only negative impact is on vibration levels relative to a generic standard.

As illustrated previously, there have been no degrading trends associated with vibration data points 1H and 5H for -24.5 years (Figures 2b and 3b). Since June 2002, filtered data (removal of one-third pump running speed to one-half pump running speed frequencies) has been recorded in addition to the current code-required values for vibration points 1H and 5H (reference Figures 2c and 3c for data since 2010). In reviewing this data, the trends are lower in value, steady, and without the spikes that the code-required data contains. This further supports the fact that the spikes in the original code data are due to the piping-induced, non-detrimental vibration occurring at the one-third to one-half pump running speed.

NLS2015026 Page 25 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

II. Consultation - Pump Manufacturer/Vibration Expert (Key Component No. 2)

A. Pump Manufacturer Evaluation of CS-P-B Vibrations Byron Jackson is the pump manufacturer for CS-P-B. The pump is an 8 x 14 x 30 DVSS, vertical mount, single stage centrifugal pump. The pump impeller is mounted on the pump motor's extended shaft. As outlined in the Core Spray System Summary of Preoperational Test, the data obtained for the B Core Spray Pump indicated high vibration. The high vibration had been recognized early in the construction testing phase, and Byron Jackson sent a representative to the site to investigate. In a letter dated February 16, 1973, the Byron Jackson representative indicated the following:

1. Tests indicated that the natural frequency of the pump was 940 revolutions per minute (rpm) (approximately one-half pump speed) in the direction of the piping and 720 rpm (between one-third and one-half of pump speed) in the direction perpendicular to the piping.
2. Observation of the test signals on the oscilloscope showed very conclusively that the motor was vibrating with randomly distributed bursts of energy, the frequency of which matched the natural frequency of the total system. This can only mean that the energy is coming from the hydraulic disturbances found in the piping.
3. Whenever large flows are carried in piping, there is usually considerable turbulence associated with the elbows, tees, etc., of the piping configuration, all of which results in piping reactions and motion. Apparently, the vibrating piping was, in turn, vibrating the pump.
4. When jacks were installed between the top of the pump and the bottom of the motor flange in an effort to stiffen the motor pump system, the motor vibrations went up due to more energy being transmitted from the pipe-pump system into the motor.
5. Testing was performed to determine any weaknesses in the pump-motor mechanical system. The vibration amplitude using the IRD instrument, with the filter set at operating speed, sampled many points vertically along the pump-motor structure. Plots of the data (along with phase angle determined by means of the strobe light) showed very clearly that the total structure was vibrating as a rigid assembly from the floor mounting. Examination of the high amplitude vibration signals showed them to be at the extremely low system natural frequencies as determined earlier.
6. Such low acceleration levels, along with the system acting as a rigid structure (between motor and pump), means that the motor and pump can operate

NLS2015026 Page 26 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) with these levels of vibration with absolutely no impairment of operating life.

This is the picture that seems very clearly described by the data obtained during these tests. There is absolutely no reason to restrict the operation of these pumps in any way.

Although the vibration was found to be acceptable, CNS took actions to install new pipe supports as an attempt to reduce these piping-induced vibrations. This action was successful as will be discussed in a later section of this relief request.

B. CNS Expert Analysis of CS-P-B Vibrations As the Vibration Monitoring Program expanded in the early 1990s, it became evident that the low frequency, piping-induced vibrations still remained in CS-P-B. Design Change (DC)94-046 resulted in the replacement of the orifices in the test return line. A March 16, 1995, memo to the CNS IST Engineer from the CNS Lead Civil/Structural Engineer discussed the CS-P-B vibration measurements obtained during DC 94-046 acceptance testing.

The vibration data was collected using peak velocity measuring instrumentation as required for the performance of the IST test and with instrumentation that provides displacement and velocity versus frequency data. It was observed that the significant vibrations in the 1H direction were occurring around 700 cycles per minute (cpm), while the pump speed is at 1780 cpm (i.e., rpm). Given the piping movement of the system, and the knowledge that piping vibrations can commonly occur in the 700 cpm (12 Hz) range, CNS concluded that the pump vibrations were piping dependent.

The CNS Lead Civil/Structural Engineer concluded that the significant pump vibrations are occurring at less than one-half of the pump operating speed. The pumps are rigidly mounted at their bases, and any impeller-induced vibrations would occur at the pump running speed or at the vane passing frequency. Therefore, the sub-synchronous pump vibrations are clearly piping induced, non-detrimental to pump/motor service or reliability, and should not be used as a basis for pump degradation. This is because the purpose of pump in-service testing is to diagnose and trend internal pump degradation.

The memo further states that the vibration data collection requirement specified in the IST procedure consists of peak velocity recordings, which may be masked by piping-induced vibrations, negating internal pump degradation diagnosis and trending. Based on the historical trending data for both CS pumps, the vibration has remained at a consistent amplitude, trending neither upward nor downward, indicating that the induced vibrations are not impairing pump operability, nor capable of preventing the pump from fulfilling its safety function. The piping vibration is present when flow is present through the test return line. It was visually observed during DC 94-046 acceptance testing that piping vibrations were minimal when flow was directed through the minimum flow line.

NLS2015026 Page 27 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

Following the DC 94-046 testing, CNS noted that the deflections observed in the discharge piping were significantly reduced. Based on these results, it was determined by the Nuclear Engineering Department, Civil/Structural Group, that the CS Loop B piping vibration stresses are less than the endurance limit of the piping.

On October 17, 2002, a Plant Engineering Supervisor at CNS, knowledgeable in the area of pump vibration analysis, issued a memo to the CNS Risk & Regulatory Affairs Manager discussing the low frequency vibration issue with the CS-P-B.

In the memo, it is stated that the pipe is vibrating as a reaction to flow turbulence, which in turn is causing the pump to vibrate. The memo documents the basis for why the low frequency vibration (less than one-half pump running speed) experienced during CS-P-B operation is not indicative of degrading pump performance and is not expected to adversely impact pump operability. To summarize, in the area of pump performance, aside from the randomness of the low frequency peaks, the spectral data shows no degrading trend in performance over several years of data. The low frequency piping-induced vibrations are not expected to adversely impact pump operability.

C. Independent Industry Vibration Expert Evaluation of CS-P-B In 2001, Machinery Solutions, Inc. was retained to perform an independent study of the CS-P-B vibrations. The following discussion was obtained from their report, issued in September of 2001. Machinery Solutions, Inc. utilized seven transducers and acquired data from CS-P-B continuously while it was operating, and data was stored every 3 seconds. Orbit plots, spectrum plots, bode and polar plots, cascade/waterfall plots, overall amplitude plots, trend plots, XY graph plots, and tabular lists were utilized to analyze the data. The data obtained by Machinery Solutions, Inc., indicated that the vibration amplitudes during the run were much higher at the top of the motor than they were at the bottom of the motor. The amplitudes decreased even further on the pump.

The spectrum plots showed that most of the vibration was occurring below running speed. They also showed that the low frequency vibration is a different frequency in each direction. The predominant peaks occur at approximately 870 cpm (less than one-half pump running speed) in line with discharge and at approximately 630 cpm (less than one-half pump running speed) perpendicular to discharge. The amplitude of each of these peaks varied significantly from second to second. The natural frequency of the pump-motor-piping structure was determined via impact testing prior to starting the pump. The natural frequencies were determined to be approximately 830 cpm in line with discharge and 670 cpm perpendicular to discharge. Such a vibration response is typical for vertical pumps.

NLS2015026 Page 28 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

Machinery Solutions, Inc. concluded the following:

I1. Most of the vibration that is measured on the motor casing is due to excitation of the structural resonances of the motor/pump by turbulent flow. These structural resonances are poorly damped and can be easily excited. Most vertical pumps have similar types of behavior, and it is not necessarily problematic by itself. A problem occurs when a pump has a continuous forcing function whose frequency coincides with a resonance (i.e., running speed). The forcing function in this case is flow turbulence caused in large part by the S-curve in the piping just off the pump discharge. The flow through this area generates lateral broadband forces, due to elbow effects, that excite the resonances in a non-continuous fashion. This is why the amplitude swings so dramatically on the motor case (the location of vibration points 1H and 5H). The system goes from brief periods of excitation to brief periods of no excitation. The discharge riser is also moving side to side from the same forces. Although the discharge piping configuration is both non-standard and less than optimum for this application, it poses no threat to the long-term reliability of either the pump or the motor. The only negative impact is on vibration levels relative to a generic standard.

2. The balance condition of the motor and pump are acceptable with no corrective action required at this time.
3. The shaft alignment between the motor and the pump is acceptable for long-term operation.
4. There is no evidence of motor bearing wear.

Machinery Solutions, Inc. recommended the following actions:

I1. Create a new IST vibration data point configuration within the data collector database to use an overall level that is generated from spectral data above 950 cpm. This will eliminate the energy from the resonances from the data set and still allow for protection from bearing degradation, impeller degradation, and motor malfunctions. The only potential failure mode that could occur within this excluded frequency range would be a fundamental train pass frequency generated by a rolling element bearing. This frequency only occurs with increased bearing clearance.

On vertical machines, this increased bearing clearance causes increased bearing compliance and the IX component will become larger. The IX change will be evident in the monitored data set.

NLS2015026 Page 29 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

2. Continue to acquire the old data points with the low-frequency data "for information only" to verify that the system response does not change.

HI. Attempts to Lower Vibration (Key Component No. 3)

CNS installed additional pipe restraints during the preoperational period in order to reduce piping-induced vibrations. Testing on October 26 and 27, 1973, following the installation of these new supports, demonstrated significantly reduced vibrations. Low-frequency piping-induced vibrations continued, but with reduced amplitude following the installation of the pipe restraints. However, the issue resurfaced in the early 1990s when additional vibration points were recorded, more strict acceptance criteria were adopted for vibrations, and new technology was incorporated into the CNS vibration program.

These new points were more influenced by the low-frequency piping-induced vibrations than the one or two points recorded in the 1980s. It was evident that the piping-induced vibrations were still prevalent with the CS-P-B pump.

In 1993, a deficiency report was written to address increased frequency IST testing of CS-P-B due to vibration. It was suspected that the pump vibrations were piping induced.

Preliminary investigation of the vibration issue concluded that cavitation at the CS test return line throttle valve and/or restriction orifices was likely causing the elevated piping vibration in both CS System loops. Vibration testing of the CS piping confirmed this conclusion.

To reduce these flow-induced vibrations, DC 94-046 was developed to replace the existing simple, single-stage orifices on both CS subsystem test return lines with multi-stage orifices. Post-installation testing with these multi-stage orifices demonstrated lower vibration levels on CS-P-A, but higher vibration levels on CS-P-B. A multi-hole single-stage orifice was fabricated and installed in the CS-P-B test return line (and later in the CS-P-A test return line) with significantly improved results. Visual observation and vibration data collected during acceptance testing determined that CS-P-B pump vibrations had been reduced, but one direction (location 1H in Figure 1) still demonstrated peak velocity reading in the alert range. The pump vibrations in the 1H direction were occurring at frequencies much lower than the pump operating speed.

The major vibration peaks were occurring at approximately 700 (cpm), while the pump speed is at 1780 cpm, indicating that the vibration was piping induced. It was also observed during acceptance testing that vibrations were minimal during operation in the minimum flow condition.

IV. Spectral Analysis (Key Component No. 4)

Figures 7 through 11 in this relief request show spectrum plots for CS-P-B, as well as spectrum trends. These plots show that the peak energy spikes for points 1H and 5H

NLS2015026 Page 30 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) remain below one-half pump running speed and that the pump vibration signature remains fairly uniform. Figure 12 shows that pump differential pressure is consistently acceptable. This data validates the analysis performed by Machinery Solutions, Inc., and the earlier conclusions that the elevated vibrations are piping induced, and not indicative of degraded pump performance. No pump or motor faults and/or degradation are evident in the spectral analysis for this pump. This test data also shows that the vibrations experienced remain in the region of the CS-P-B pump-motor-piping system natural frequency, at less than half the pump's operating speed.

Vibrations occurring at these low frequencies are not expected to be detrimental to the long-term reliability of either the pump or the motor. Typical pump faults, i.e., impeller wear, bearing problems, alignment problems, shaft bow, etc., would result in measurable vibration response in frequencies equal to or greater than one-half of the pump's running speed. Such faults would also be evident in pump trends. However, the vibrations are being experienced below one-half pump operating speed, have existed since initial operation, and are not trending higher. Visual inspection by Machinery Solutions, Inc., in 2001 of the pump base plate, soleplate, and grout, identified no visible cracks or degradation. Further, they concluded that the balance condition and shaft alignment of the pump and motor were acceptable, and detected no evidence of motor bearing wear.

D. Maintenance History The maintenance history for CS-P-B reflects that there have been no significant work items applicable to CS-P-B due to the low-frequency vibrations that have been experienced since the construction phase of the plant. A review of maintenance history for the CS-P-B pump and motor was performed.

The search consisted of a historical review of CS-P-B pump and motor maintenance in addition to a more general search of CS System vibrational issues. This search identified that the pump and motor installed in the plant today is the same combination that was installed during the construction phase of the plant. Some of the key items reviewed are summarized below:

1. 1973: Additional supports installed on "B" CS System during pre-operational stage. As discussed previously, this resulted in lowering CS-P-B vibrations.
2. January 1977: Vibration eliminator on "B" CS test line, CS-VE7, required tightening of wall plate bolts per Maintenance Work Request (MWR) 77-1-10.

Bolts in pipe clamp were replaced and clamp was realigned. Design was determined to be adequate, but lock washers should be used to prevent recurrence of the problem. MWR 77-1-262 completed this action.

NLS2015026 Page 31 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

3. April 1989 (Work Item [WI] 89-0269); November 1991 (WI 91-1507), February 1993 (MWR #92-2876): CS-P-B stator end turn bracing brackets inspected for stress corrosion cracking or unusual conditions such as loose bolts or bending.

No cracks, loose bolts, or other unusual conditions were observed.

4. March 1993: A magnetic particle examination of CS-P-B support attachment weld revealed an indication at Lug #5 of the pump support. The indication was ground out, repaired, and retested satisfactorily. The indication was very small and would not have affected the overall stiffness of the pump. In 2003, no recurrence of this indication was identified.
5. April 1993: Work Order #93-1631 was initiated due to mechanical seal leakage.

A complete inspection of the pump/motor was also completed. The pump was found with the keyway not properly aligned with the mechanical seal, causing the leakage. The impeller was found to have minor pitting at the base of the wear ring area. The pump casing and cover had minor erosion and pitting. No significant problems with the pump or motor were noted.

6. July 1994: Bolt torque checked for lower end bell and lower bearing housing on CS-P-B motor due to a loose bolt found on the "A" RHR pump motor. No movement on lower bearing housing bolts. Movement of lower end bell bolts were as follows: 1/16 flat on #1, 3, 4, and 5 and no movement on #2, 6, 7, and 8.

These were very minor adjustments.

7. Late 1994: DC 94-046 installs new orifices in CS-P-B test line. As previously discussed, this reduced piping deflections in the test line.
8. Oil Samples (Dates: 09-22-95, 10-22-95, 11-24-95, 02-28-97, 03-26-98, 04 99, 01-24-00, 12-26-00, 10-28-02, 08-30-04, 01-05-05, 08-14-06, 02-28-07, 08-14-07, 02-11-08, 08-14-08, 02-19-09, 08-12-09, 02-09-10, 08-25-10, 03-11-11, 09-02-11, 12-13-11, 03-02-12, 08-24-12, 02-12-13, 08-13-13, 02-11-14, 08 14): Periodic Oil Sample Analysis of the upper and lower motor bearings in accordance with Preventive Maintenance Program. Results of CS-P-B Motor oil analysis were satisfactory with no corrective actions required.
9. Numerous Visual Motor Inspections completed satisfactory (i.e., January of 2002): Visual motor inspection satisfactory per Work Order #4199724.
10. February 2003: Notification #10225272 identified an indication approximately 3/8" on a CS-P-B integral attachment (CS-PB-Al). The indication is at the top of one of the small gusset supports where the gusset is welded to the cast pump

NLS2015026 Page 32 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) bowl extension (different spot than the 1993 indication). Within Engineering Evaluation 03-030, the indication was determined to be on the gusset side of the weld and appears to be an incomplete fusion of the weld and not a service load-induced flaw. Poor accessibility was the most likely cause. Engineering Calculation 03-007 demonstrated that, even if the five minor gusset plates were ignored, the pump support is still qualified under the most severe design loads.

This search of the maintenance history, covering a time period of approximately forty years, identified no significant maintenance or corrective actions that had to be implemented for the "B" CS pump and motor due to the piping-induced vibrations. Only minor indications were noted on the pump impeller and casing during the last significant motor/pump disassembly in 1993.

No other documentation of pump/motor disassembly inspection results was found during this review. Oil analyses of the CS-P-B lower and upper motor bearing housings were found to be satisfactory for all the results documented since 1995 to the present. Wear metals, contaminants, additives, etc., were all at acceptable levels. The addition of pipe supports in 1973 and new orifices in the test lines were necessary modifications and were previously discussed. Other than these modifications, only minor corrections have been made with pipe and/or pump supports (tightening bolts, minor indication, etc.), none of which were found to be significant. Therefore, the maintenance history supports the basis of this relief request in that the piping-induced vibrations occurring on CS-P-B have not degraded the pump or motor in any way.

E. Basis for Code Alternative Alert Values for Points 1H and 5H By this relief request, NPPD is proposing to increase the absolute alert limit for vibration points 11H and 5H from 0.325 in/s to 0.400 in/s. The piping-induced vibration, which occurs at low frequencies, occasionally causes the overall vibration value for these two points to exceed 0.325 in/s, resulting in CS-P-B being on an increased test frequency.

However, several expert analyses and maintenance history reviews have shown that this piping-induced vibration has not resulted in degradation to the pump. Additionally, the overall vibration levels have remained steady over the past -24.5 years. Therefore, it has been demonstrated that doubling the test frequency under the current conditions does not provide additional assurance as to the condition of the pump and its ability to perform its safety function.

These new values are reasonable as they represent an alternative method that still meets the intended function of monitoring the pump for degradation over time while keeping the required action level unchanged. The proposed values encompass the majority of the historical values, but not all of them (reference Figures 2a, 2b, 3a, 3b). With these new values, a reading above 0.400 in/s would require NPPD to place the pump on an increased testing frequency and to evaluate the pump performance to determine the cause

NLS2015026 Page 33 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) of the reading. It is expected that a small amount of degradation occurring in the pump or a slight increase in the piping-induced vibration would be quickly identified with these new parameters.

The new alert limits will still allow for early detection of pump degradation or piping-induced vibration increases prior to component failure, while the required action absolute limit will remain at the code value of 0.700 in/s. Therefore, the intent of the code will be maintained.

Conclusions Several expert evaluations have documented that no internal pump or motor degradation is occurring due to the piping-induced vibration, which has been present since the pre-operational testing time period. The available vibration data over the past -24.5 years and differential pressure data over nearly the past -20 years supports this fact as essentially no degradation has been indicated. A maintenance history review and review of oil analyses results further supports these conclusions.

Based on this information, CNS concludes that doubling the test frequency for CS-P-B does not provide additional information nor does it provide additional assurance as to the condition of the pump and its ability to perform its safety function. Testing of this pump on an increased frequency places an unnecessary burden on CNS resources.

All four key components discussed in NUREG/CP-0 152 have been addressed in detail, supporting the alternative testing recommended in this relief request.

CNS concludes that CS-P-B is operating acceptably and will perform its safety function as required during normal and accident conditions. The increased alert limits proposed for vibration points I H and 5H in this relief request will continue to assure long-term reliability of CS-P-B.

During the performance of CS-P-B inservice comprehensive pump testing, or any other time vibrations are recorded to determine pump acceptability (i.e., post-maintenance testing, other periodic testing, etc.), pump vibration shall be monitored in accordance with ISTB-3510(e) and ISTB-3540(a). The acceptance criteria for vibration points 2H, 3H, and IV will follow the criteria specified in ISTB Table ISTB-5121-1. The acceptance criteria of vibration points 1H and 5H will have increased absolute alert limit values of 0.400 in/s. The absolute required action limits for all points will continue to be 0.700 in/s in accordance with ISTB Table ISTB-5121-1. The absolute alert and required action limits for all vibration points associated with CS-P-B are summarized in the table below.

NLS2015026 Page 34 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

Absolute Vibration Acceptance Criteria for CS-P-B:

Vibration Acceptable Range Alert Range Required Action Parameter Range 1H < 0.400 in./sec. >0.400 in./sec. >0.700 in./sec.

5H < 0.400 in./sec. > 0.400 in./sec. > 0.700 in./sec.

IV < 0.325 in./sec. >0.325 in./sec. > 0.700 in./sec.

2H < 0.325 in./sec. >0.325 in./sec. > 0.700 in./sec.

3H < 0.325 in./sec. > 0.325 in./sec. > 0.700 in./sec.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RP-07 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 35 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CS-P-B Figures Figure Description Attach. 2 Number Page Number 1 CS-P-B Vibration Monitoring Points 36 2a CS-P-B Vibration Point 1H from November 1996 to the Present 37 2b CS-P-B Vibration Point 11H from April 1990 to the Present 38 2c Trend of Vibration Point 1H with Data Below One-Half Pump 39 Running Speed Filtered from May 2010 to the Present 3a CS-P-B Vibration Point 5H from November 1996 to the Present 40 3b CS-P-B Vibration Point 5H from April 1990 to the Present 41 3c Trend of Vibration Point 5H with Data Below One-Half Pump 42 Running Speed Filtered from February 2010 to Present 4a CS-P-B Vibration Point 1V from November 1996 to the Present 43 4b CS-P-B Vibration Point IV from April 1990 to the Present 44 5a CS-P-B Vibration Point 2H from November 1996 to the Present 45 5b CS-P-B Vibration Point 2H from April 1990 to the Present 46 6a CS-P-B Vibration Point 3H from November 1996 to the Present 47 6b CS-P-B Vibration Point 3H from April 1990 to the Present 48 7 Spectral Trend for Vibration Point IH 49 8 Spectral Trend for Vibration Point 5H 50 9 Spectral Trend for Vibration Point 1V 51 10 Spectral Trend for Vibration Point 2H 52 11 Spectral Trend for Vibration Point 3H 53 12 CS-P-B Differential Pressure since January 1995 to the Present 54

NLS2015026 Page 36 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 1v

-1 SUCTION 62CS101A Figure 1 CS-P-B Vibration Monitoring Points

NLS2015026 Page 37 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 1flVib(11H) (tbsc)

  • V~b (IH) Ar AVib (H)ACI 0 FMONSWg CS4LB Vbrabon Pofft'lfr Fmm Nw4ember IM IDI* ReWt I

&131 116l996e 06!14120 O1rzl2MO Owl2WaO 04mISII I1VI@a14 Figure 2a CS-P-B Vibration Point 1H from November 1996 to the Present

NLS2015026 Page 38 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 10 Vb (1H) @*W) * ~ IHb ,j Vib(I' c Qrmuaausw CS" Vbrabm Pwd -lIr Fmm Apd MO IDftMUt I

(L49.

0.37-0.19 0-131 W411990 I1.

0311Ml99 i¶?

=2 6 00V V l00r5 12M1112000 1111012014 Figure 2b CS-P-B Vibration Point 1H from April 1990 to the Present

NLS2015026 Attachment 2 Page 39 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CORE SPRAY PUMP MOTOR 8 1H - MOTOR UPPR HORLZONTAL SOUTl*IH0) 14.83-1KHZ IST

- Basehne-Value: 0.135 511811 12:00AM 211212015 11:20-11 PM Amp: 0 120 1112412012 532:33 PM 0.28 RoLte 0392 V -DG Pk 0394 LOAD - 10W00 RPM - 1700.

(2967 Hr) 021 0.14 0-07 j LL.-

01--*~~~

0 10000 L

20000 I

320D0 Frequency (CPM)

W6000

-I Freq57133.l 80000 Ord:32.10 AMP. 0.00M9 List of Trend Points Station: REACTOR BUILDING Machine: CS-MOT-B --> CORE SPRAY PUMP MOTOR B Meas Point: 1H --> MOTOR UPPR HORIZONTAL SOUTH (H01)

Parameter: 14.83-1KHZ (PK Velocity in In/Sec)

Date Time Value Date Time Value 10-May-10 14:21 .103 16-May-13 11:28 .109 16-Nov-10 13:09 .109 13-Nov-13 12:35 .108 21-Apr-11 15:06 .135 13-May-14 22:51 .124 Early Warning Limits --- .169 24-May-11 13:43 .110 14-Aug-14 10:55 .112 Alert Limit Values --- .300 23-Nov-11 13:32 .122 12-Oct-14 02:08 .130 Fault Limit Values --- .700 23-May-12 10:51 .125 10-Nov-14 23:21 .120 24-Nov-12 17:32 .113 12-Feb-15 23:20 .120 Figure 2c Trend of Vibration Point 1H with Data Below One-Half Pump Running Speed Filtered from May 2010 to the Present

NLS2015026 Page 40 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 1M VIb (SH) WXCC) 0 VI ) A v6 (") Achm 0 Fwrecm" CS-"~b~

Via .*t 'u Fi wre.bw 1996tb. Pmaw BIM

'El 0-%

0.49

,a SM f 0-5 6 0-22 0.19 I IIAWUSM 061140 WJW2N4 04R12011 ltl/102014 Figure 3a CS-P-B Vibration Point 5H from November 1996 to the Present

NLS2015026 Page 41 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 1 IEb(5H (wfec)

  • V6 (5H) Abt A vb (5H) go 0 rWWDS&V CS-P-S Vbrafw ft;it 5W fum AM 1990b ODReMs*

GM4 I

&ý23 N -4 0.16-0110 W4f11990 03Y1411995 02/12r2000 01I11n t 5 121 MI2009 1111*02014 Figure 3b CS-P-B Vibration Point 5H from April 1990 to the Present

NLS2015026 Attachment 2 Page 42 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CORE SPRAY PUMP MOTOR B / 5H - MOTOR UPPR HORIZONTAL WEST (HOS) 14.83-1KI-HZ IST

- Baseline -

0.3 .Value: 0.269 0226- W1all9M8 12:00 AM

(_ 0I 2112/2 3 5 2011 2012 2013 2014 2015 11:21:36PM Amp, 0.266 2112/2015 112136 PM 0.28- Rot" 0,374 V -D0 Pk -0374 LOAD - 100 00 RPM - 178Of (29867 Hz) 021-0 0ý07 -

0+~:

0 1L .1 10000 '0000 30r00 Frequency(OCPM) 40000 60000

-I 80000 FreqF31 SO4 OCOL1.792 Aaiwp 0,00558 List of Trend Points Station: REACTOR BUILDING Machine: CS-MOT-B --> CORE SPRAY PUMP MOTOR B Meas Point: 5H --> MMOTOR UPPR HORIZONTAL WEST (HOS)

Parameter: 14.83-1KHZ (PK Velocity in In/Sec)

Date Time Value Date Time Value 09-Feb-10 14:48 .252 24-Nov-12 17:32 .229 10-Feb-10 10:04 .252 16-May-13 11:30 .223 10-May-10 14:21 .238 13-Nov-13 12:35 .243 Early Warning Limits --- .309 16-Nov-10 13:09 .252 13-May-14 22:52 .262 Alert Limit Values --- .300 21-Apr-11 15:06 .238 14-Aug-14 10:56 .224 Fault Limit Values --- .700 24-May-11 13:43 .201 12-Oct-14 02:09 .229 23-Nov-11 13:33 .215 10-Nov-14 23:22 .250 23-May-12 10:52 .232 12-Feb-15 23:21 .266 Figure 3c Trend of Vibration Point 5H with Data Below One-Half Pump Running Speed Filtered from February 2010 to the Present

NLS2015026 Page 43 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 0Ui (IV09w *V6 (IV) abt A Vuib(MV Ack 0 Fnafr CS.4aB Mir Point' FromNvme 19 oOwPe OME 0.,$3 0.53 0.47-OA1 023 0.17 0.11 WM41 ("ar"

~1 1111012014 Figure 4a CS-P-B Vibration Point 1V from November 1996 to the Present

NLS2015026 Page 44 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

I ib(IV) (Wtsec)

  • ib(1V) AWi V)I AcV) 0QFM.MU" CS-"~ Vbat Po" -IV- FM AM IOkwftu.@

190 t 0.U 0.56-0.50.

0.44

... - Z -_-0_-

0,32 020, 1k]-- &%.. &Yi TA~ A.joe 0.14!

041411990 031UM1905 021121000 O~1112006 w1r2/112 11/10M2014 Date Figure 4b CS-P-B Vibration Point IV from April 1990 to the Present

NLS2015026 Page 45 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued) 10 VIb (2) fr*uc)

  • VIb M Ai A Vib M)Acb 0 F-Ia CS4LB VAwsbon Post W Fmm Novaidw 1996 IDIhe Prewt 0-54 0.50 0.46 0.42 0.34 0.30 0.13 00i5 It-d99 011U2004 04-li rnIIOFI4 ode Figure 5a CS-P-B Vibration Point 2H from November 1996 to the Present

NLS2015026 Page 46 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

IM Vb (M) Ofte)

  • Vmb0 AW~ A vi w1 Acbm 0 mAie CS-PLs Vivan PofV2H'rFra Apri 1990 IDR Retw I

0461Si r - 7- a -

041141990 01141995 0212M00 0111 1200 12111009 111*02014 Ode Figure 5b CS-P-B Vibration Point 2H from April 1990 to the Present

NLS2015026 Page 47 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

  • ~ 31)Aw A Vib (3H) Acfwn 0 wMMOSin" 0.59 0-53 GýllI 01 ltIM24 Dab Figure 6a CS-P-B Vibration Point 3H from November 1996 to the Present

NLS2015026 Page 48 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

Vib Ma) (f 0 V6i (M)AJrt A Vib (311) AiCin 0 FMMOft CS4LB8 vmaho Po3rt -W ti.November 19M6 W tP~f 0,53 0.47 0.41 0.35 *6e em... .. ze;~o.~eu.ee.
  • e; .e~z~eeo~~

0.231 0.17-

.1110 1995 06fl412M0 0 1r2IQD04 04MM11 1102014 Figure 6b CS-P-B Vibration Point 3H from April 1990 to the Present

NLS2015026 Page 49 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CORE SPRAY PUMP MOTOR B I 1H - MOTOR UPPR HORIZONTAL SOUTH(H1) 211212015 11:20:11 PM 0.28. Route 0.302 V-DO Pk= 0.302 LOAD= 100.00 RPM = 1780.0 0.21 (29.67 Hz)

CD

. 0.14 0.07-U4 LI1 LI ,

10600 I.

2000 3000 40000 so60o

, Freq:1260.0 60000 Ord:0.708 Frequency (CPM) Amp: 0.00844 CORE SPRAY PUMP MOTOR B / 1H - MOTOR UPPR HORIZONTAL SOUTHI1)

-0.28 C,,

C C

I 0

I 0,

a- 211212015 ii 11/1012014

.1 h I 10/1212014 I 8/14t2014 5/1312014 0.28- k 11/1312013 1111 ~

49 1I ki I 5/110/2013 III Ii t112412012 5/23U2012

. **11./2312011

. 5/24.2011

_ 41212011 9L j 1 ~ 1/1=12010 15110t2010 1 0

,46WO0 0 1500 30000 I000 Frequency (CPM)

Figure 7 Spectral Trend for Vibration Point 1H

NLS2015026 Page 50 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CORE SPRAY PUMP MOTOR B I 5H - MOTOR UPPR HORIZONTAL WEST (H05) 2/1212015 11:21:36PM 0.28 Route 0.374 V-DO Pk= 0.374 LOAD= 100.00 RPM = 1780.0 0.21 (29.67 Hz) 0.14 a._

0.07 Freq:1 260.0 10000 3Fqc0 Ord:0.708 Frequency (CPM) Amp: 0.00770 CORE SPRAY PUMP MOTOR B/ 5H - MOTOR UPPR HORIZONTAL WEST (H05)

-028 0) i]i U 'IJ 0)

I-

, , A 2/12/2015 1111012014

~1011212014 0.28 I hip.

11.1 I*IT[ I I I tl FA41I Ii i

IL I~

~

I.

Ii I

5113f2014 11113/2013

............ 511612013 I I 5-L II 11124Q2012 5123/2012 1112312011

/ 5t2412011 ILJPflfljj U iF. 412112011 W111162010 2A12/2015 11:21 PM RPM: 1780.0 5/11012010 0 Y Freq:5981 0.6 0 10000 20000 30000 4000 50000 60000 Ord:33.60 Frequency (CPM) Amp: 0.0001 Figure 8 Spectral Trend for Vibration Point 5H

NLS2015026 Page 51 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CORE SPRAY PUMP MOTOR 8 1IV - MOTOR UPPR AXIAL (VO1) 2/1212015 11:19:19 PM

02. Route 0.191 V-DO Pk= 0.191 LOAD = 100 00 RPM = 1780.0 0.154 (29.67 HF U

U)

C

£ 014 U

2 4) a-0.05.

'6 i-~ L 1060o 20000 3000 40600

, , Freq,586688 60000 Ord:32.96 Frequency (CPM) AMp 0.00030 CORE SPRAY PUMP MOTOR B IV - MOTOR UPPR AXIAL (VO)

-02

-01 S02-I.,

IJ 1 I r-~

ii '

In I.

V 11212014 0/1402014 Al CL 8M1142014 1 1/13,2013 II

  • I I I I~IIt1 ~ in~ W/2013
  • lMJ I I II 1,12401 012 ri i . i w L .... llk_.

i I

II J .L I

5Mr,/012 Wf41201 1 4121/2011 2/A122015 m,"r'a-r'--.'--- I 11.19PM J:¥,_.l I . L I I

-~ 111 120=10 I A1.~I RPM: 17800 V,.] li I I 0510/20 tO Freq;S9810 6 10000 20000 30000 40000 50000 e0000 Ord:33.S0 Frequency (CPM) Amp 0.0001 Figure 9 Spectral Trend for Vibration Point 1V

NLS2015026 Page 52 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

CORE SPRAY PUMP MOTOR BI 2H - MOTOR LWR HORIZONTAL SOUTHI(H02) 21121201511:2221 PM 0.08 Route u ] 0.104 V-DG 0.067-r - Pk =0.105 LOAD =100.00 C 0.053- ..

RPM = 1780.0 2'

(-3 0.04 .. (29.67 Hz)

O0.027 .

S0.013-I-0.

0 10oo 2o06 o 400 600 Frequency (CPM)

CORE SPRAY PUMP MOTOR B 12H - MOTOR LWR HORIONTAL SOUTH0(02)

-0.1

- 0.025 2 10.2/12/2014

./161 2013 0.054- 11124/2012 30000 40000 50000 80000 Frequency (CPM)

Figure 10 Spectral Trend for Vibration Point 2H

NLS2015026 Page 53 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

RX - CORE SPRAY PUMP MOTOR B CS-MOT-B -3H MOTOR LWR HORIZONTAL WEST (H03) 2/12/2015 11:23:07 PM 0-1! Route 0.183 V -DG Pk = 0.183 0.1; LOAD = 100.00 RPM = 1780.0 U. (29.67 Hz) 0 0.1 M

Freq:59850 0 Ord:33.62 Frequency (CPM) Amp: 0.00039 CORE SPRAY PUMP MOTOR B I 3H - MOTOR LWR HORIZONTAL WEST (W103)

-0.2

-0.1

.C_ 3 2/12,2016

.* 0.2-11V1012014

/ 5/1312014 1111312013 0.1 11t24(2012 123n2012 S1112312011 5r2412011 2f1 2f2015 4t2112011 11:23 PM RPM: 1780.0

& 111=12010 Freq: 59968.1 Ord:33.69 0 30000 4)600 50000 o0060 Amp: 0.0004 Frequency (CPM)

Figure 11 Spectral Trend for Vibration Point 3H

NLS2015026 Page 54 of 99 Relief Request RP-07 Core Spray Pump B Vibration Alert Limits (Continued)

IE VET Piug ti' ow-Ach

  • OffRem. (d)~OWM Offfts W)'ih'"M 0 ' .

CS4LB ftnbW Ressum Fnqm"suay 1995 IoheReset 30120O I

271.70 265.80 0mAe19e5 12r"9 12lW2OM 12RM2PQS 1irwo 11V1W0M4 Dale Figure 12 CS-P-B Differential Pressure Since January 1995 to the Present

NLS2015026 Page 55 of 99 Relief Request RP-08 Comprehensive Pump Test Upper Limit Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected All Pumps within the IST scope.
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-5123 "Comprehensive Test Procedure," (e), refers to Table ISTB-5121-1, which utilizes a multiplier of 1.03 times the reference value for the comprehensive pump test's upper "Acceptable Range" and "Required Action Range High" criteria.

ISTB-5223 "Comprehensive Test Procedure," (e), refers to Table ISTB-5221-1, which utilizes a multiplier of 1.03 times the reference value for the comprehensive pump test's upper "Acceptable Range" and "Required Action Range High" criteria.

ISTB-5323 "Comprehensive Test Procedure," (e), refers to Tables ISTB-5321-1 and ISTB-5321-2, both of which utilize a multiplier of 1.03 times the reference value for the comprehensive pump test's upper "Acceptable Range" and "Required Action Range High" criteria.

4. Reason for Request Occasionally, NPPD has had some difficulty with implementing the high required action range limit of 1.03% above the established hydraulic parameter reference value due to normal data scatter. NPPD has had to address an inoperability of a pump on at least two occasions during the fourth ten-year interval in which a pump was declared inoperable during a comprehensive pump test due to exceeding this upper limit. The result was that the plant had to enter (or remain in) an applicable Technical Specification Limiting Condition for Operation (LCO) for reasons other than a pump degradation issue.

Based on the similar difficulties experienced by other Owners, ASME OM Code Case OMN-19 was developed and has been published in the 2011 Addenda of the ASME OM Code. The white paper for this code case, Standards Committee Ballot 09-610, record 09-657, discussed the impact of instrument inaccuracies, human factors involved with setting and measuring test parameters, readability of gauges and other miscellaneous factors on the ability to meet the 1.03% acceptance criteria. Industry operating experience is also discussed in the white paper.

NLS2015026 Page 56 of 99 Relief Request RP-08 Comprehensive Pump Test Upper Limit (Continued)

Code Case OMN-19 has not yet been approved for use in RG 1.192, "Operations and Maintenance Code Case Acceptability, ASME OM Code."

Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the multiplier of 1.03 times the reference value for the comprehensive pump test's upper "Acceptable Range" and "Required Action Range High" criteria, referenced in Tables ISTB-5121-1, ISTB-5221-1, ISTB-5321-l, and ISTB-5321-2. The proposed alternative would provide an acceptable level of quality and safety.

5. Proposed Alternative and Basis for Use CNS proposes to use the ASME OM Code Case OMN-l 9 as published in the 2011 Addenda of the ASME OM Code for the fifth ten year interval IST Program. The ASME OMN-19 Code Case allows for the use of a multiplier of 1.06 times the reference value in lieu of the 1.03 multiplier for the comprehensive pump test's upper "Acceptable Range" criteria and "Required Action Range, High" criteria referenced in the applicable ISTB test acceptance criteria tables ISTB-5121-1, ISTB-5221-1, ISTB-5321-1 and ISTB-5321-2.

The bases for the approval of OMN- 19, as discussed in the Standards Committee Ballot white paper, are summarized below:

1) Instrument inaccuracies of measured hydraulic value.
2) Instrument inaccuracies of set value and its effect on measured value.
3) Instrument inaccuracies and allowed tolerance for speed.
4) Human factors involved with setting and measuring flow, D/P, and speed.
5) Readability of Gauges based on the smallest gauge increment.
6) Miscellaneous Factors.

These inaccuracies may cause the measured value to exceed the existing code allowed comprehensive pump test's upper "Acceptable Range" criteria and the "Required Action Range, High" criteria of 3%. The new upper limit of 6%, as approved in Code Case OMN-19, will eliminate declaring the pump inoperable and entering an unplanned Technical Specification LCO or will eliminate the extension of an existing LCO.

As a condition for using OMN-19, CNS will implement a pump periodic verification (PPV) test program to verify that a pump can meet the required differential (or discharge) pressure, as applicable, at its highest design basis accident flow rate, as discussed in Mandatory Appendix V, which was published in the 2012 Edition of the ASME OM Code. CNS will not be required to perform a PPV test if the design basis accident flow rate in the licensee's safety analysis is bounded by the comprehensive pump test or Group A test. Also, if a pump does not have a design basis accident flow rate, then a PPV test is not required. Therefore, any IST pump that is utilizing the 1.06 multiplier for the comprehensive pump test will meet this condition.

NLS2015026 Page 57 of 99 Relief Request RP-08 Comprehensive Pump Test Upper Limit (Continued)

Using the upper limit of 1.06 times the reference value in lieu of the 1.03 multiplier for the comprehensive pump test's upper "Acceptable Range" criteria and "Required Action Range, High" criteria referenced in the applicable ISTB test acceptance criteria tables will provide an acceptable level of quality and safety.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was approved for the fourth ten-year interval at Columbia Generating Station as RP-06 (TAC Nos. MF3847, MF3848, MF3849, MF3851, MF3852, MF3853, MF3854, MF3855, MF3856, MF3857, and MF3858, December 9 and February 9, 2015).

NLS2015026 Page 58 of 99 Relief Request RP-09 Variance Around the Reference Values Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected All Pumps within the IST scope.
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTB-5121 Group A Test Procedure ISTB-5122 Group B Test Procedure ISTB-5123 Comprehensive Test Procedure ISTB-5221 Group A Test Procedure ISTB-5222 Group B Test Procedure ISTB-5223 Comprehensive Test Procedure ISTB-5321 Group A Test Procedure ISTB-5322 Group B Test Procedure ISTB-5323 Comprehensive Test Procedure
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), an alternative is proposed to the pump testing reference value requirements of the ASME OM Code. The basis of the request is that the proposed alternative would provide an acceptable level of quality and safety.

For pump testing, there is difficulty adjusting system throttle valves with sufficient precision to achieve exact flow reference values during subsequent IST exams. Section ISTB of the ASME OM Code does not allow for variance from a fixed reference value for pump testing. However, NUREG-1482, Revision 2, Section 5.3, acknowledges that certain pump system designs do not allow for the licensee to set the flow at an exact value because of limitations in the instruments and controls for maintaining steady flow.

NLS2015026 Page 59 of 99 Relief Request RP-09 Variance Around the Reference Values (Continued)

ASME OM Code Case OMN-21 provides guidance for adjusting reference flow/DP to within a specified tolerance during Inservice Testing. The Code Case states "It is the opinion of the Committee that when it is impractical to operate a pump at a specified reference point and adjust the resistance of the system to a specified reference point for either flow rate, differential pressure or discharge pressure, the pump may be operated as close as practical to the specified reference point with the following requirements. The Owner shall adjust the system resistance to as close as practical to the specified reference point where the variance from the reference point does not exceed +2% or - 1% of the reference point when the reference point is flow rate, or + 1% or -2% of the reference point when the reference point is differential pressure or discharge pressure."

5. Proposed Alternative and Basis for Use CNS seeks to perform Inservice Pump testing in a manner consistent with the requirements as stated in ASME OM Code Case OMN-21. Specifically, testing will be performed such that flow rate is adjusted as close as practical to the reference value and within proceduralized limits not to exceed +2%/-1% of the reference value. Or, if differential pressure or discharge pressure is set, then it will be set as close as practical to the reference value and within proceduralized limits not to exceed + 1%/-2% of the reference value.

CNS plant operators will still strive to achieve the exact test flow reference values during testing.

Typical test guidance will be to adjust flow to the specific reference value. If necessary, additional guidance will be provided such that if the reference value cannot be achieved with reasonable effort, the test will be considered valid if the steady state reference value is within the procedural limits. The procedural limits will be carefully determined on a case by case basis, and will not exceed the limits provided in Code Case OMN-2 1. The test will be considered valid if the steady state reference value is within the proceduralized limits of the procedure.

Using the provisions of this request as an alternative to the specific requirements of ISTB-5121, ISTB-5122, ISTB-5123, ISTB-5221, ISTB-5222, ISTB-5223, ISTB-5321, ISTB-5322, and ISTB-5323 as described above will provide adequate indication of pump performance and continue to provide an acceptable level of quality and safety.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was approved for Callaway for their fourth ten-year interval as PR-06 (TAC Nos. MF2784, MF2785, MF2786, MF2787, MF2788, and MF2789, July 15, 2014).

NLS2015026 Page 60 of 99 Relief Request RV-01 LPCI Solenoid Operated Drain Valve Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Valve Class Category System HPCI-SOV-SSV-64 2 B HPCI HPCI-SOV-SSV-87 2 B HPCI
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTC-3300 Reference Values - Reference values shall be determined from the results of preservice testing or from the results of inservice testing.

ISTC-3310 Effects of Valve Repair, Replacement, or Maintenance on Reference Values - When a valve or its control system has been replaced, repaired, or has undergone maintenance that could affect the valve's performance, a new reference value shall be determined or the previous value reconfirmed...

ISTC-3500 Valve Testing Requirements - Active and passive valves in the categories defined in ISTC-1300 shall be tested in accordance with the paragraphs specified in Table ISTC-3500-1 and the applicable requirements of ISTC-5 100 and ISTC-5200.

ISTC-35 10 Exercising Test Frequency - Active Category A, Category B, and Category C check valves shall be exercised nominally every 3 months except as provided by ISTC-3520, ISTC-3540, ISTC-3550, ISTC-3570, ISTC-5221, and ISTC-5222.

ISTC-3560 Fail-Safe Valves - Valves with fail-safe actuators shall be tested by observing the operation of the actuator upon loss of valve actuating power in accordance with the exercising frequency of ISTC-35 10.

ISTC-5151 Valve Stroke Testing -

(a) Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.

(b) The limiting value(s) of full-stroke time of each valve shall be specified by the Owner.

(c) Stroke time shall be measured to at least the nearest second.

ISTC-5152 Stroke Test Acceptance Criteria - Test results shall be compared to reference values established in accordance with ISTC-3300, ISTC-33 10, or ISTC-3320.

ISTC-5153 Stroke Test Corrective Action.

NLS2015026 Page 61 of 99 Relief Request RV-01 HPCI Solenoid Operated Drain Valve Testing (Continued)

4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the listed requirements of the ASME OM Code. The proposed alternative would provide an acceptable level of quality and safety.

The HPCI turbine and exhaust steam drip leg drain to gland condenser (HPCI-SOV-SSV-64) and HPCI turbine and exhaust steam drip leg drain to equipment drain isolation valve (HPCI-SOV-SSV-87) have an active safety function in the closed position to maintain pressure boundary integrity of the HPCI turbine exhaust line. These valves serve as a Class 2 to non-code boundary barrier.

These valves are rapid acting, encapsulated, solenoid-operated valves. Their control circuitry is provided with a remote manual switch for valve actuation to the open position and an auto function which allows the valves to actuate from signals received from the associated level switches HPCI-LS-98 and HPCI-LS-680. Both valves receive a signal to change disc position during testing of drain pot level switches. However, remote position indication is not provided for positive verification of disc position. Additionally, their encapsulated design prohibits the ability to visually verify the physical position of the operator, stem, or internal components.

Modification of the system to verify valve closure capability and stroke timing is not practicable nor cost beneficial since no commensurate increase in safety would be derived.

5. Proposed Alternative and Basis for Use CNS has been performing a robust exercise test for these two valves that verifies obturator movement since 1998 on a quarterly basis. In 2001, this test identified some leakage past HPCI-SOV-SSV64 and the valve was removed and refurbished. For the past -14 years, the exercise test has been completed without any issues. This test is accomplished through the performance of surveillance procedure, 6.HPCI.204, HPCI-SOV-SSV64 and HPCI-SOV-SSV87 IST Closure Test. With HPCI not in operation, a demineralized water source is utilized to verify that HPCI-SOV-SSV64 opens when level switch HPCI-LS-680 (turbine exhaust drain pot high level) trips, allowing level in the gland seal condenser to start to rise due to water flow through HPCI-SOV-SSV64. After HPCI-LS-680 resets and HPCI-SOV-SSV64 closes, the gland seal condenser level is verified to be steady.

Similarly, CNS verifies that HPCI-SOV-SSV87 opens when level switch HPCI-LS-98 (turbine exhaust drip leg high) trips, allowing the observation of water flow to a floor drain from a drain pipe downstream of HPCI-SOV-SSV87. After HPCI-LS-98 resets and HPCI-SOV-SSV87 closes, CNS observes the drain pipe downstream of HPCI-SOV-SSV87 for gross leakage past the valve.

Therefore, CNS verifies valve obturator movement for both valves open and closed while simultaneously verifying the calibration of two level switches.

Typically, tests that involve hooking up pressure sources and various amounts of test tubing are not performed on a quarterly basis due to their complexities (i.e. local leak rate tests). In addition, each time this "quarterly" test has been performed, HPCI unavailability time (-1.5

NLS2015026 Page 62 of 99 Relief Request RV-01 IIPCI Solenoid Operated Drain Valve Testing (Continued) hours) is consumed in addition to some minor radiological dose. Finally, this exercise test is actually a much better method of determining the valve's operational readiness than a quarterly fast acting stroke time test would have been. Therefore, based on the complexities of the test, consuming unnecessary HPCI unavailability time and personnel radiation exposure, the exceptional test history dating back to 2001, and the fact that this is a robust test that verifies obturator movement, CNS proposes to exercise each valve to the full closed position, as described, on a 6 month basis.

In addition to performing this robust exercise test every 6 months, each solenoid valve will be disassembled and examined for degradation on a periodic basis per the Preventative Maintenance Program. The valve body, insert, piston, plunger/stem assembly, and stem spring will all be examined per criteria outlined in surveillance procedure 6.HPCI.404. In addition, continuity and the physical condition of the coil will also be checked. The valve and/or valve parts will be refurbished and/or replaced, as necessary, based on this examination. This maintenance shall be performed at an optimized frequency, not to exceed 48 months (2 cycles). The purpose of this enhanced preventative maintenance is to ensure the long term reliability of the components and to monitor for internal degradation. This is consistent with NUREG 1482, Section 4.2.3. The 6 month exercise tests will ensure that the valves are operational and will fulfill their safety function when called upon.

The robust 6 month exercise testing and the enhanced preventative maintenance will provide an adequate indication of valve performance and will continue to provide an acceptable level of quality and safety. Therefore, pursuant to 10 CFR 50.55a(h)(3)(z)(1), NPPD requests relief from the specific ISTC requirements identified in this request.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RV-01, Revision I (TAC NO. ME7021, August 28, 2012) and Revision 0 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

A version of this relief request was previously approved for the fifth ten-year interval at Dresden Nuclear Power Station as Relief Request RV-23H (TAC Nos. ME9865, ME9866, ME9869, ME9870, ME9871, and ME9872, October 31, 2013).

NLS2015026 Page 63 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Valve Class Category System MS-RV-70ARV 1 C Main Steam (MS)

MS-RV-70BRV 1 C MS MS-RV-70CRV 1 C MS

2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTC-5240 - Safety and Relief Valves. Safety and relief valves shall meet the inservice test requirements of Mandatory Appendix I.

ASME OM Code Mandatory Appendix I, "Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants," Section 1-1320, "Test Frequencies, Class I Pressure Relief Valves," paragraph (a), "5-Year Test Interval," states that Class I pressure relief valves shall be tested at least once every 5 years.

4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirements of ASME OM Code Appendix I, 1-1320(a). The proposed alternative would provide an acceptable level of quality and safety.

Section ISTC-3200, "Inservice Testing," states that inservice testing shall commence when the valves are required to be operable to fulfill their required function(s). Section ISTC-5240, "Safety and Relief Valves," directs that safety and relief valves meet the inservice testing requirements set forth in Appendix I of the ASME OM Code. Appendix I, Section 1-1320(a), of the ASME OM Code states that Class 1 pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation. This section also states a minimum of 20 percent of the pressure relief valves are tested within any 24-month interval and that the test interval for any individual valve shall not exceed 5 years. Prior to Cycle 28, CNS had refueling cycles of 18 months. With three safety valves, CNS has been meeting the ASME OM Code by removing,

NLS2015026 Page 64 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued) testing, rebuilding, and re-installing one valve per refueling outage. All three of these safety valves have an acceptable test history since 1997 as will be described in section 5.

However, after Refueling Outage (RE) 27 (Fall/2012), CNS began the current 24-month refueling cycle. The five year frequency was met for the safety valve due in RE28 (Fall/2014), but a relief request, requesting the use of Code Case OMN-17, will be necessary in order to continue with the process of testing only one valve each refueling outage for the fifth ten-year interval, beginning March 1, 2016. Without this relief request, CNS would be required to remove and test all three valves within a two cycle frequency (two one outage and one the next) in order to ensure that all three valves are removed and tested in accordance with the ASME OM Code requirements. This testing pattern would ensure compliance with the ASME OM Code requirements for testing Class 1 pressure relief valves within a 5 year interval.

Extending the test interval to 6 years, as described in Code Case OMN-l17, would allow CNS to continue with the current method of removing, testing, rebuilding, and re-installing one safety valve per outage so that all three safety valves would be replaced over three refuel cycles (i.e., -6 years).

Without Code relief, the incremental outage work due to the inclusion of an additional safety valve every other outage would be contrary to the principle of maintaining radiation dose As Low As Reasonably Achievable (ALARA). The removal and replacement of the additional safety valve every other outage results in an additional exposure of approximately 450 millirem (mrem) to 726 mrem. This estimate is based on the actual radiation received to remove and re-install a safety valve each of the last three refueling outages.

In accordance with 10 CFR 50.55a(h)(3)(z)(1), NPPD requests approval of an alternative to the 5 year test interval requirement of the ASME OM Code, Appendix I, Section 1-1320(a) for the safety valves at CNS.

5. Proposed Alternative and Basis for Use NPPD requests that the test interval be increased from 5 years to 6 years in accordance with Code Case OMN-17. All aspects of Code Case OMN-17 will be followed for the MS safety valves.

As an alternative to the Code required 5-year test interval per Appendix I, paragraph 1-1320(a),

NPPD proposes that the subject Class 1 safety valves be tested at least once every three refueling cycles (approximately 6 years/72 months) with a minimum of 20% of the valves tested within any 24-month interval. This 20% would consist of valves that have not been tested during the current 72-month interval, if they exist. The test interval for any individual valve would not exceed 72 months except that a 6-month grace period is allowed to coincide with refueling outages to accommodate extended shutdown periods and certification of the valve prior to installation. This is all in accordance with OMN-17, paragraph (a).

After as-found set-pressure testing, the valves shall be disassembled and inspected to verify that parts are free of defects resulting from time-related degradation or service induced wear. As-left

NLS2015026 Page 65 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued) set-pressure testing shall be performed following maintenance and prior to returning the valve to service. Each valve shall have been disassembled and inspected prior to the start of the 72-month interval. Disassembly and inspection performed prior to the implementation of Code Case OMN-17 may be used.

Each refueling outage, CNS will remove one safety valve to be sent off-site to a test facility.

Upon receipt at the off-site facility, the valves are subject to an as-found inspection, as-found seat leakage test, and as-found set pressure test in accordance with Appendix I of the ASME OM Code. Prior to the returning the valve to the plant for re-installation, the safety valve is disassembled and inspected to verify that internal surfaces and parts are free from defects or service induced wear. During this process, anomalies or damage are identified for resolution.

Damaged or worn parts (i.e. springs, gaskets and seals) are replaced or repaired, as necessary.

Following reassembly, the valve's set pressure is recertified. This existing process is in accordance with ASME OM Code Case OMN-17, paragraphs (d) and (e). Alternatively, CNS may elect to replace the removed valve with a spare valve that has previously already been through the process just described. Up to three spare valves may be used in accordance with paragraph (b) of OMN-17.

NPPD has reviewed the as-found set point test results for all three safety valves tested since 1997 as detailed in Table 1. Since 1997, all as found lift tests have been within a +/-3% tolerance (maximum of +2.02%). The current Technical Specification requirements are that the as found test results fall within a +/-3% tolerance. Technical Specifications require the as left certification of the valves to meet a +/-1% tolerance. If an as found test is found to be outside of the +/-3%

tolerance, the other 2 safety valves will be removed and tested in accordance with Code Case OMN-17, paragraph (c).

Accordingly, the proposed alternative of implementing all aspects of OMN-1 7, which will increase the test interval for the subject Class 1 safety valves from 5 years to 3 fuel cycles (approximately 6 years/72 months), will provide an acceptable level of quality and safety. This will also restore the operational and maintenance flexibility that was lost when the 24-month fuel cycle created the unintended consequences of more frequent testing. This proposed alternative will continue to provide assurance of the valves' operational readiness and provides an acceptable level of quality and safety pursuant to 10 CFR 50.55a(h)(3)(z)(1).

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents A similar relief was previously approved at Peach Bottom for the fourth ten-year interval as Relief Request 01A-VRR-3 (TAC Nos. MF2509 and MF2510, April 30, 2014).

NLS2015026 Page 66 of 99 Relief Request RV-02 Main Steam Safety Valve Testing per Code Case OMN-17 (Continued)

Monticello Nuclear Generating Plant Relief Request VR-04 was approved in a NRC Safety Evaluation Report dated September 26, 2012 (ML12244A272).

Quad Cites Nuclear Power Station, Units I and 2 Relief Request RV-05 was approved in a NRC Safety Evaluation Report dated February 14, 2013 (ML13042A348).

Table 1: Cooper Nuclear Station Safety Valve Test History AF Test Date Set Pressure As Found Set Deviation from Safety Valve Pressure Set Pressure 4/9/1997 1240 1217 -1.85%

10/9/1998 1240 1252 +0.97%

MS-RV-70ARV 3/8/2003 1240 1226 -1.13%

4/19/2008 1240 1232 -0.65%

10/21/2012 1240 1255 +1.21%

4/10/1997 1240 1226 -1.13%

3/12/2000 1240 1231 -0.73%

MS-RV-70BRV 1/25/2005 1240 1241 +0.08%

10/3/2009 1240 1260 +1.61%

10/8/2014 1240 1253 +1.05%

4/10/1997 1240 1262 +1.77%

11/12/2001 1240 1237 -0.24%

MS-RV-70CRV 10/26/2006 1240 1265 +2.02%

3/21/2011 1240 1262 +1.77%

NLS2015026 Page 67 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Valve Class Category System MS-RV-71ARV 1 B/C MS MS-RV-71BRV 1 B/C MS MS-RV-71CRV 1 B/C MS MS-RV-71DRV 1 B/C MS MS-RV-71ERV 1 B/C MS MS-RV-71FRV 1 B/C MS MS-RV-71GRV 1 B/C MS MS-RV-71HRV 1 B/C MS
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTC-5240 - Safety and Relief Valves. Safety and relief valves shall meet the inservice test requirements of Mandatory Appendix I.

ASME OM Code Mandatory Appendix I, "Inservice Testing of Pressure Relief Devices in Light-Water Reactor Nuclear Power Plants," Section 1-1320, "Test Frequencies, Class 1 Pressure Relief Valves," paragraph (a), "5-Year Test Interval," states that Class 1 pressure relief valves shall be tested at least once every 5 years.

ASME OM Code Mandatory Appendix I, 1-3310 Class I Main Steam Pressure Relief Valves with Auxiliary Actuation Devices - Tests before maintenance or set-pressure adjustment, or both, shall be performed for 1-3310(a), (b) and (c) in sequence. The remaining shall be performed after maintenance or set-pressure adjustments:

a. visual examination;

NLS2015026 Page 68 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)

b. seat tightness determination, if practicable;
c. set-pressure determination;
d. determination of electrical characteristics and pressure integrity of solenoid valve(s);
e. determination of pressure integrity and stroke capability of air actuator;
f. determination of operation and electrical characteristics of position indicators;
g. determination of operation and electrical characteristics of bellows arm switch;
h. determination of actuating pressure of auxiliary actuating device sensing element, where applicable, and electrical continuity;
i. determination of compliance with the Owner's seat tightness criteria.
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(1), relief is requested from the requirements of ASME OM Code Appendix I, sections 1-1320(a) and 1-3310. The proposed alternative would provide an acceptable level of quality and safety.

Section ISTC-5240, "Safety and Relief Valves," directs that safety and relief valves meet the inservice testing requirements set forth in Appendix I of the ASME OM Code.

Appendix I, Section I-1320(a), of the ASME OM Code states that Class 1 pressure relief valves shall be tested at least once every 5 years, starting with initial electric power generation. This section also states a minimum of 20 percent of the pressure relief valves are tested within any 24-month interval and that the test interval for any individual valve shall not exceed 5 years.

CNS has eight MS safety relief valves (SRV). The approach for the past several years has been to remove either 2 or 3 of the entire valves (i.e. main body and pilot assembly) every refueling outage and send them off for as found testing, refurbishment, rebuilding, and re-certification in preparation for the next time they are re-installed into the plant. Those 2 or 3 entire valves have been replaced with refurbished valves that were recertified just prior to the outage. The schedule is planned so that all eight entire valves get sent off, as found tested, refurbished, and re-certified within a three cycle frequency. In addition, CNS has replaced the remainder of the pilot assemblies (5 or 6 per outage) and sent them off for testing, refurbishment, and re-certification in preparation for the next time they are re-installed into the plant. These 5 or 6 additional pilot assemblies are replaced with refurbished and recertified pilot assemblies that were recertified just prior to the outage. Therefore, the pilot assemblies for the full complement of 8 valves have been set pressure tested every outage for several years.

NLS2015026 Page 69 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)

CNS plans to continue this approach into the fifth ten-year interval. However, refueling outage 27 (Fall/2012) was the last refueling outage under an 18-month cycle. CNS is now operating with 24-month cycles. With this in mind, the refurbishment of the entire valves will eventually align with a six year frequency, which is consistent with Code Case OMN-1 7. However, all eight of the pilot assemblies are being removed, tested and replaced with refurbished/recertified spare pilot assemblies every refueling outage, which means a full complement of the set pressure portion of the valves are being tested every refueling outage. Therefore, although this approach is very conservative, documenting acceptability of this approach is being pursued per this relief request.

Additionally, since 5-6 pilot assemblies, alone, are being replaced every outage (versus the entire valve), documenting acceptability of how portions of Appendix 1-33 10 are being satisfied is also being pursued per this relief request.

5. Proposed Alternative and Basis for Use These eight SRVs are considered Class 1 main steam pressure relief valves with auxiliary actuating devices. They are located on the main steam lines. In addition to their automatic function of opening to prevent over pressurization of the reactor vessel, six of these valves are associated with the Automatic Depressurization System and two are associated with the Low Low Set logic. The valves are two-stage Target Rock valves, each equipped with a main body, a pilot assembly for set pressure control, a solenoid valve, and an air operator assembly.

CNS proposes to follow the Code Case OMN-17, paragraph (d), recommendations for Maintenance on these eight valves. Therefore, on a three cycle (up to 6 year) frequency, CNS proposes to remove the entire valve unit (i.e. main body and pilot assembly) for each one of these valves and ship it off for as found testing, refurbishment, and re-certification. CNS will replace these entire valve units with spare refurbished and re-certified entire valve units.

As mentioned earlier, each valve is equipped with a pilot valve assembly that controls the set pressure. The remainder of the pilot valve assemblies (5 or 6 per refueling outage) will be removed from the main body and sent off site for examination, as found testing, refurbishment, and re-qualification testing (set point, reseat, and pilot stage seat tightness). The test facility has a main body slave for this purpose. The removed pilot valve assemblies are replaced with previously refurbished and re-qualified pilot valve assemblies. By testing all of the pilot valve assemblies every outage, the potential need to expand to test additional valves due to set pressure failures is alleviated and the future valve reliability is improved. Test results are being monitored by serial numbers. Any as found set pressure failure will be addressed via the CNS Corrective Action Program.

ASME OM Code Interpretation, 98-8, clarifies that a pilot operated relief valve with an auxiliary actuating device is not required to be tested as a unit. Furthermore, it clarifies that set pressure determination on the pilot operator may be performed after the pilot operator is removed from the valve body.

NLS2015026 Page 70 of 99 Relief Request RV-03 Main Steam Safety Relief Valve Testing (Continued)

Appendix I, 1-3310(a) visual examination is completed at the test facility for those main bodies and pilot assemblies being sent there for examination, testing and refurbishment. With the removal of the pilot assemblies from the main bodies at the plant, the accessible portions of the main bodies will be examined in place without further disassembly as permitted by 1-1310(c).

Appendix I, 1-3310(b) seat tightness, and 1-3310(c) set pressure, is satisfied through as found seat leakage and set pressure testing at the offsite test facility for those main valves and pilot valve assemblies being sent there for inspection, testing and refurbishment. Paragraph 1-3310(i) is satisfied through as left seat leakage testing at the facility. Seat leakage of installed main valves is continuously monitored and also satisfies 1-3310(i). Pressure switches in the SRV discharge lines annunciate in the control room and indicate when the main valve seat is open. In addition, there are temperature elements on the valve discharge lines which provide leakage indication.

During startup, the main valve and Auxiliary Actuation Devices are verified to function properly by being full stroke exercised open and closed. Successfully exercising these valves open and closed verifies the electrical characteristics and pressure integrity of the solenoid valve and air actuator (satisfying Appendix I, paragraphs (d) and (e)). During this exercise, Appendix I, paragraph 1-3310(f), is also satisfied through the use of the valve indicating lights, discharge pressure switches, and temperature elements.

Finally, Appendix I, paragraphs 1-3310(g) and 1-3310(h), are not applicable to the CNS MS safety relief valves.

This proposed alternative is conservative in nature and will continue to provide an acceptable level of quality and safety pursuant to 10 CFR 50.55a(h)(3)(z)(1).

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as Relief Request RV-04 (TAC Nos. MC8837, MC8975, MC8976, MC8977, MC8978, MC8979, MC8980, MC8981, MC8989, MC8990, MC8991, and MC8992, June 14, 2006).

NLS2015026 Page 71 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Valve Class Category System CRD-SOV-SO120* 2 B CRD CRD-SOV-SO121* 2 B CRD CRD-SOV-SO122* 2 B CRD CRD-SOV-SO123* 2 B CRD CRD-AOV-CV126* 2 B CRD CRD-AOV-CV127* 2 B CRD CRD-CV-114CV* 2 C CRD CRD-CV-138CV* 2 C CRD SOV=Solenoid Operated Valve AOV=Air Operated Valve CV=Check Valve
  • Typical of 137 Hydraulic Control Units (HCU)
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ASME OM Code ISTC-3500 Valve Testing Requirements - Active and passive valves in the categories defined in ISTC-1300 shall be tested in accordance with the paragraphs specified in Table ISTC-3500-1 and the applicable requirements of ISTC-5 100 and ISTC-5200.

ISTC-3510 Exercising Test Frequency - Active Category A, Category B, and Category C check valves shall be exercised nominally every three (3) months, except as provided by ISTC-3520, ISTC-3540, ISTC-3550, ISTC-3570, ISTC-5221, and ISTC-5222.

ISTC-3560 Fail-Safe Valves - Valves with fail-safe actuators shall be tested by observing the operation of the actuator upon loss of valve actuating power in accordance with the exercising frequency of ISTC-35 10.

ISTC-5131 (a) Valve Stroke Testing - Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.

ISTC-5151 (a) Valve Stroke Testing - Active valves shall have their stroke times measured when exercised in accordance with ISTC-3500.

NLS2015026 Page 72 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing (continued)

ISTC-5221 (a) Valve Obturator Movement - The necessary valve obturator movement during exercise testing shall be demonstrated by performing both an open and a close test.

4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(l), relief is requested from the requirements of ASME OM Code ISTC-3500, ISTC-35 10, ISTC-3560, ISTC-5131 (a),

ISTC-5151 (a), and ISTC-5221 (a). The proposed alternative would provide an acceptable level of quality and safety.

This relief is needed to make the fifth ten-year inservice test program consistent with NUREG 1482, Revision 2.

5. Proposed Alternative and Basis for Use Background Information It is typical for Boiling Water Reactors (BWR) to perform the subject CRD testing per their respective plant Technical Specifications. This originated from Generic Letter (GL) 89-04, Position 7. Per section 1.3 of NUREG 1482, Revision 2, specific relief is required to implement the guidance derived from GL 89-04, which is why this testing is being documented under a relief request. The proposed alternatives and the basis for use are discussed in further detail below.

CRD-CV-138CV; CRD-SOV-SO120, SO121, S0122, SO123:

The CRD cooling water header check valve, CRD-CV-I 38CV (typical of 137 HCUs), has a safety function to close in the event of a scram to prevent diversion of pressurized HCU accumulator water to the cooling water header. The exhaust water withdrawal/settle (CRD-SOV-SO 120), exhaust water insert (CRD-SOV-SO 121), drive water withdrawal (CRD-SOV-SO 122),

and drive water insert (CRD-SOV-SO 123) solenoid valves (typical of 137), have a safety function to close in order to provide a boundary to non-code class piping.

Normal control rod motion will verify that the associated cooling water check valve has moved to its safety function position of closed. Industry experience has shown that rod motion may not occur if this check valve were to fail in the open position.

The solenoid valves listed above have a safety function to close in order to provide a class 2 to non-code class boundary isolation. During normal operation, these solenoid valves are used for control rod insertion and withdrawal. They are exercised open and closed during normal operation of the associated CRD. They are not equipped with position indication or control switches. They automatically change position to affect control rod movement.

Therefore, control rod exercising in accordance with the CNS Technical Specifications, Surveillance Requirement (SR) 3.1.3.3, will provide an acceptable level of quality and safety for these valves. This testing method is consistent with GL 89-04, Position 7, and NUREG 1482, Revision 2, Section 4.4.6.

NLS2015026 Page 73 of 99 Relief Request RV-04 Control Rod Drive (CRD) Technical Specification Testing (continued)

CRD-AOV-CV 126, CRD-AOV-CV 127, and CRD-CV- 114CV:

These valves operate as an integral part of their respective HCU to rapidly insert the control rods in support of a scram. The CRD scram inlet valve, CRD-AOV-CV126 (typical of 137), opens with a scram signal to pressurize the lower side of the Control Rod Drive Mechanism (CRDM) pistons from the accumulator or from the charging water header. The CRD outlet isolation valve, CRD-AOV-CV 127 (typical of 137), opens with scram signal to vent the top of the CRDM piston to the scram discharge header. The CRD scram outlet check valve, CRD-CV-1 14CV (typical of 137), opens to allow flow from the top of the CRDM piston to the scram discharge header.

Individual stroke time measurements of air-operated valves CRD-AOV-CVI126 and CRD-AOV-CV 127 are impractical due to their rapid acting operation and they are not equipped with position indication. Therefore, valve stroke times will not be measured. Additionally, the air-operated valves fail-open on a loss of air or power. Normal opening removes power to the pilot solenoid valve, simulating a loss of power. On loss of power, the solenoid vents the air operator and CRD-AOV-CV 126 and CRD-AOV-CV 127 are spring-driven open. Thus, each time a scram signal is given, the valves "experience" a loss of air/power to verify each valve's fail-safe open feature.

Testing these valves simultaneously would result in a full reactor scram. An excess number of scrams performed routinely could cause thermal and reactivity transients, which could lead to fuel, vessel, CRD, or piping damage. The CRDs cannot be tested during cold shutdown because the control rods are inserted and must remain inserted.

Therefore, control rod scram time testing in accordance with the CNS Technical Specifications, SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4, will provide an acceptable level of quality and safety for these valves. This testing method for these valves is consistent with GL 89-04, Position 7, and NUREG 1482, Revision 2, Section 4.4.6.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was previously approved for the fourth ten-year interval at CNS as relief request RV-06 (TAC No. ME1521, April 26, 2010). A similar alternative was approved at Perry-1 for relief request VR-1, revision 1 (TAC No. ME7380, February 22, 2012).

NLS2015026 Page 74 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests Proposed Alternative in Accordance with 10 CFR 50.55a(h)(z)(3)(1)

Alternative Provides Acceptable Level of Quality and Safety

1. ASME Code Component(s) Affected Valve Class Category System RHR-MOV-MO25A 1 A RHR RHR-MOV-MO25B 1 A RHR RHR-MOV-MO274A I A RHR RHR-MOV-MO274B 1 A RHR RHR-CV-26CV I A/C RHR RHR-CV-27CV 1 A/C RHR RHR-MOV-MO17 1 A RHR RHR-MOV-MO18 1 A RHR CS-MOV-MO 12A I A CS CS-MOV-MO12B 1 A CS CS-CV-18CV 1 A/C CS CS-CV-19CV 1 A/C CS MOV=Motor Operated Valve
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Requirement ISTC-3630 - Leakage Rate for Other Than Containment Isolation Valves.

ISTC-3630(a) - Frequency. Tests shall be conducted at least once every two years.

4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and standards," paragraph (h)(3)(z)(1), relief is requested from the requirement of ASME OM Code ISTC-3630(a). ISTC-3630(a) requires that leakage rate testing (water) for pressure isolation valves (PIV) be performed at least once every two years.

Data from RE25 and RE26 was used to identify that PIV testing alone each refueling outage incurs a total dose of at least 600 mRem. The reason for this relief request is to reduce outage dose. The basis of this relief request is that the proposed alternative would provide an acceptable level of quality and safety.

5. Proposed Alternative and Basis for Use The RHR and CS systems at CNS contain valves that function as PIVs. PIVs are defined as two normally closed valves in series at the reactor coolant system boundary that isolate the reactor

NLS2015026 Page 75 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued) coolant system from an attached low pressure system. These affected valves, listed in Section 1, are located on the 'A' and 'B' CS and RHR injection lines and the RHR shutdown cooling line.

PIVs are not specifically included in the scope for performance-based testing as provided for in 10 CFR 50 Appendix J, Option B. The concept behind the Option B alternative for containment isolation valves is that licensees should be allowed to adopt cost effective methods for complying with regulatory requirements. Additionally, NEI 94-01, Revision 0, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," describes the risk-informed basis for the extended test intervals under Option B. That justification shows that for valves which have demonstrated good performance by passing their leak rate tests (air) for two consecutive cycles, further failures appear to be governed by the random failure rate of the component. NEI 94-01 also presents the results of a comprehensive risk analysis, including the statement that "the risk impact associated with increasing [leakrate] test intervals is negligible (less than 0.1 percent of total risk)." The valves identified in this relief request are in water applications. The PIV testing is performed with water pressurized to normal plant operating pressures. This relief request is intended to provide for a performance-based scheduling of PIV tests at CNS.

As stated in the previous section, the reason for requesting this relief is dose reduction. Data reviewed from RE25 and RE26 identified that PIV testing alone incurred a total dose of approximately 600 mrem in RE26, which benefited from the chemical decontamination that was performed, and approximately 1600 mrem in RE25. Therefore, assuming the PIVs remain classified as good performers, extended test intervals of three refueling outages would provide a savings of at least 1200 mrem over a three-cycle period.

NUREG 0933, "Resolution of Generic Safety Issues," Issue 105, discusses the need for PIV leak rate testing based primarily on three pre-1980 historical failures of applicable valves industry-wide. These failures involved human errors in either operations or maintenance. None of these failures involved inservice equipment degradation. The performance of PIV leak rate testing provides assurance of acceptable seat leakage with the valve in a closed condition. Typical PIV testing does not identify functional problems which may inhibit the valves ability to re-position from open to closed. For check valves, such functional testing is accomplished per ASME OM Code ISTC-3522 and ISTC-3520. Power-operated valves are routinely full stroke tested per ASME OM Code to ensure their functional capabilities. The periodic functional testing of the PIVs is adequate to identify abnormal conditions that might affect closure capability.

Performance of the separate 24-month PIV leak rate testing does not contribute any additional assurance of functional capability; it only determines the seat tightness of the closed valves.

NLS2015026 Page 76 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)

The functional test and position indication test (PIT) frequencies are as follows:

Valve Functional Test PIT RHR-MOV-MO25A Quarterly 2 years RHR-MOV-MO25B Quarterly 2 years RHR-MOV-MO274A Normally De-energized Closed Refueling Outage (exercised during PIT test)

RHR-MOV-MO274B Normally De-energized Closed Refueling Outage (exercised during PIT test)

RHR-CV-26CV Refueling Outage Refueling Outage RHR-CV-27CV Refueling Outage Refueling Outage RHR-MOV-MO17 Cold S/D Refueling Outage RHR-MOV-MO 18 Cold S/D Refueling Outage CS-MOV-MO 12A Cold S/D Refueling Outage CS-MOV-MO 12B Cold S/D Refueling Outage CS-CV-18CV Refueling Outage Refueling Outage CS-CV-19CV Refueling Outage Refueling Outage CNS proposes to perform PIV testing at intervals ranging from every refueling outage to every third refueling outage. The specific interval for each valve would be a function of its performance and would be established in a manner consistent with the containment isolation valve (CIV) process under 10 CFR 50 Appendix J, Option B. Five of the 12 valves listed in Section 1 (RHR-MOV-MO25A, RHR-MOV-MO25B, CS-MOV-MO12A, CS-MOV-MO12B, RHR-MOV-MO 17) are also classified as CIVs and are leak rate tested with air at intervals determined by 10 CFR 50 Appendix J, Option B. Appendix J and inservice leak testing program guidance will be established such that if any of those five valves fail either their as found CIV test or their PIV test, the test interval for both tests will be reduced to every refueling outage until they can be re-classified as good performers per Appendix J, Option B requirements.

The test intervals for the seven remaining valves with a PIV-only function will be determined in the same manner as is done under Option B. That is, the test interval may be extended to every three refueling outages (not to exceed a nominal six year period) upon completion of two consecutive, periodic PIV tests with results within prescribed acceptance criteria. Any test failure will require a return to the initial interval (every refueling outage) until good performance can again be established.

The primary basis for this relief request is the historically good performance of the PIVs. There have been no PIV seat leakage failures since PIV testing began at CNS in 1995 through the present. Leakages recorded have been a very small percentage of the overall allowed leakage.

NLS2015026 Page 77 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)

The test results for the PIVs listed in Section 1 have been exceptional. For example, a plot of the RHR-MOV-MO17 test results is shown below:

hWLeakap 2 $*Leekss2AIam La RHR.MOV-M017 PlV Test Dat 4.50 4.00 3,50 3.00

a. 2.50 0

1.50 1.00 0.50 0.00 U 11MAM95 1201906 01M= 0 05 03110120= 041012011 Date This graph is typical of the affected PIVs listed in Section 1; however, there have been cases where the CIV air testing has indicated a failure with components identified in this relief request.

There is a general industry-wide consensus that CIV air testing is a more challenging and accurate measurement of seat condition, and more likely to identify any seat condition degradation. PIV testing has also been utilized at CNS as a post-maintenance test following packing replacements on the CS and RHR injection check valves to ensure the packing is adjusted adequately at normal system pressure. Therefore, PIV testing will continue to be utilized as post-maintenance testing, as necessary.

On June 8, 2012, the NRC staff reviewed and endorsed NEI 94-01, Revision 3 (see the safety evaluation at Accession No. ML121030286), which allows for up to a 75-month frequency for "Type C tests." Per the NRC safety evaluation report (SER) for the fourth interval IST Program (TAC No. ME7021, dated August 28, 2012), to obtain a frequency extension beyond 60 months (up to 75 months), licensees should provide additional information, such as maintenance history, acceptance tests criteria, condition monitoring programs, etc., to justify the acceptability of the extension. In order to further justify the proposed maximum frequency of 3 cycles (72 months) with a standard grace period of 6 months, additional information is being provided.

Table 1 of this relief request contains the maintenance history and Local Leak Rate Test (LLRT)/PIV test history for all 12 of these pressure isolation valves for the past 10 years (since 01/01/2005). The table includes the as found and as left LLRT and PIV test results with the

NLS2015026 Page 78 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued) associated operability limits. Note that corrective and preventative maintenance has been performed over the past 10 years (and beyond) in order to maintain the acceptable performance of the components. For instance, the MOV Program requires regular inspections and diagnostic tests of the motor operators to ensure that they continue to be relied upon throughout the life of the plant and the check valves have preventative maintenance plans to replace the valve packing on a periodic basis to ensure the packing material is properly maintained. Note that not all of the maintenance performed impacts the seating ability of the components or the test boundary of the associated LLRTIPIV tests, so pre- or post-LLRT/PIV testing may not have been required to be performed. Exercise testing, stroke time testing, and position indication testing was not listed in Table 1.

As can be observed from Table 1, the As Found LLRT test results have been excellent with no failures associated with these valves over the past 10 years and a significant amount of margin has been maintained to the administrative component operability limit. Even more so, a very large margin exists between the PIV test results and the operability limit for each PIV test. With a limit of 5 gpm, the highest recorded PIV leakage in the last 10 years was 0.435 gpm, which is only 8.7% of the allowed leakage. Historically, since 1995, all of the PIV valves have maintained this much or more of a margin to the 5 gpm acceptance criteria as shown below.

Test # Components Maximum PIV Percent of Percent of leakage recorded allowed leakage margin to 5 gpm since 1995 (gpm) limit I RHR-MOV-MO25A 0.299 5.98% 94.02%

2 RHR-MOV-MO25B 0.272 5.44% 94.56%

3 RHR-CV-26CV /

RHR-CV-26CV RHR-MOV-MO274A 0.1224 2.45% 97.55%

4 RHR-CV-27CV /

RHR-CV-27CV RHR-MOV-MO274B 0.326 6.52% 93.48%

5 RHR-MOV-MO17 0.0272 0.54% 99.46%

6 RHR-MOV-MO18 0.218 4.36% 95.64%

7 CS-MOV-MO12A 0.435 8.70% 91.30%

8 CS-MOV-MO12B 0.082 1.64% 98.36%

9 CS-CV-18CV 0.3264 6.53% 93.47%

10 CS-CV-19CV 0.082 1.64% 98.36%

The NRC SER for NEI TR 94-01, Revision 3, resulted in a condition that the licensee report the margin between the Type B and Type C leakage rate summation and its regulatory limit and maintain an acceptable margin to the regulatory limit. A second condition requires the licensee to include considerable extra margin in order to extend the LLRT intervals beyond 5 years to a 75-month interval. In comparison, for these PlV tests, CNS will establish an administrative limit of

<1 gpm for each of the PIV tests in order to maintain each test on an extended frequency. This administrative limit is only 20% of the allowed leakage and will provide considerable extra margin to the limit of 5 gpm when looking at the historical test results.

NLS2015026 Page 79 of 99 Relief Request RV-05 Performance-Based Scheduling of Pressure Isolation Valve Leakage Tests (continued)

NUREG/CR-5928, "ISLOCA Research Program Final Report," evaluated the likelihood and potential severity of inter-system loss-of-coolant accident (ISLOCA) events in BWR and pressurized water reactors. The BWR design used as a reference for this analysis was a BWR/4 with a Mark 1 containment. CNS was listed in Section 4.1 of NUREG/CR-5928 as one of the applicable plants. The applicable BWR systems were individually analyzed and in each case, this report concluded that the system was "...judged to not be a concern with respect to ISLOCA risk."

Section 4.3 concluded the BWR portion of the analysis by saying "ISLOCA is not a risk concern for the BWR plant examined here."

Summary of bases / rationale for this relief request:

  • Performance-based PIV testing would yield a dose reduction of up to 1200 mrem over a three-cycle period.

" Performance of separate functional testing of PIVs per ASME Code.

" Excellent historical performance results from PIV testing for the applicable valves.

  • Low likelihood of valve mispositioning during power operations (procedures, interlocks).
  • Air testing versus water testing - degrading seat conditions are identified much sooner with air testing.
  • Relief valves in the low pressure piping - these relief valves may not provide ISLOCA mitigation for inadvertent PIV mispositioning (gross leakage), but their relief capacity can easily accommodate conservative PIV seat leakage rates.

" Alarms that identify high pressure to low pressure leakage - Operators are highly trained to recognize symptoms of a present or incipient ISLOCA and to take appropriate actions.

The intent of this relief request is simply to allow for a performance-based approach to the scheduling of PIV leakage testing. It has been shown that ISLOCA represents a small risk impact to BWRs such as CNS. CNS PIVs have an excellent performance history in terms of seat leakage testing. The risks associated with extending the leakage test interval to a maximum of three refueling outages (nominal 24 months) are extremely low. The performance-based interval shall not exceed 72 months. Standard scheduling practice may extend the program interval by 25%,

not to exceed six months. This relief will provide significant reductions in radiation dose.

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents A version of this relief request was previously approved for the fourth ten-year interval at CNS as relief request RV-07 (TAC No ME7021, dated 8-28-2012). Fermi 2 received a Safety Evaluation by the NRC, dated September 28, 2010, on a similar relief request for the performance-based testing of PIVs (TAC No. ME2558, ME2557, and ME2556).

NLS2015026 Page 80 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date [ Outage I Work Order Work Order Description I AF Tests I AL Tests Comments RHR-MOV-MO25A Spring/2005 RE22 N/A N/A LLRT: N/A LLRT and (Test #1) 2.02 scfth (< 30 scfth) PIV test due.

PIV:

0.299 gpm (< 5 2Dm) 10/02/2005 Online CM 4464719 Remove insulation and N/A N/A No impact on validate leak; tightened LLRT or PIV cap screws on pressure testing.

seal; slowed leakage.

02/10/2006 Online CM 4465302 Efforts were made to stop N/A N/A No impact on bonnet seal leak. LLRT or PIV testing.

05/30/2006 Online PM 4390882 Clean & Lubricate Stem N/A N/A No impact on LLRT or PIV testing.

Fall/2006 RE23 CM 4464912 Repaired pressure seal LLRT: LLRT (Final AL): Major CM 4534360 leak, refurbed motor 0.83 scfhi (< 30 scfli) 7.95 scth ( < 30 maintenance operator, disassembled scfi)) resets LLRT and examined valve, and PIV: Freq. to every diagnostically tested. 0.08 gpm (AL) refueling outage.

04/03/2007 Online PM 4542913 Perform Motor Pinion N/A N/A No impact on Inspection LLRT or PIV testing.

10/04/2007 Online PM 4498618 Examine MO-Mech N/A N/A No impact on PM 4498668 Examine MO-Elect LLRT or PIV testing.

Spring/2008 RE24 N/A N/A LLRT: N/A 1st periodic 1.25 scfh (< 50 scflh) test for LLRT PIV: (and PIV) 0.109 gpm (< 5 test.

gpm) 03/30/2009 Online PM 4625205 Clean & Lubricate Stem N/A N/A No impact on PM 4625262 Examine MO-Mech LLRT or PIV PM 4625267 Examine MO-Elec testing.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 81 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Fall/2009 RE25 CM 4641890 MOV Program Diagnostic LLRT: PIV: No impact to test/motor replacement. 1.75 scfh (< 50 scflh) 0.109 gpm (< 5 gpm) LLRT or PIV No AL LLRT required testing. 2nd due to minimal seat thrust periodic test change. for LLRT (and PIV) test.

Spring/201 1 RE26 N/A N/A LLRT: N/A 3rd (extra) 2.1 scflh (< 50 scfh) periodic test PIV: for LLRT 0.136 gpm (< 5 (and PIV) gpm) test.

06/05/2012 Online PM 4802964 Clean and Lubricate Stem N/A N/A No impact on PM 4803040 Examine MO-Mech LLRT or PIV PM 4803052 Examine MO-Elec testing.

Fall/2012 RE27 N/A N/A N/A N/A No tests due to Option B /

approved PIV relief request.

Fall/2014 RE28 N/A N/A LLRT: N/A No PIV test 3.82 scfh (< 50 scfh) due to approved PIV relief request.

RHR-MOV-MO25B Spring/2005 RE22 CM 4335229 Votes diagnostic test LLRT: LLRT: MOV (Test #2) 24 scfh (< 30 scfhi) 23.8 sctb (< 30 scfh) periodic test.

PIV:

0.0544 gpm (< 5 gpm) 04/11/2005 Online PM 4381354 Clean and Lubricate Stem N/A N/A No impact on LLRT or PIV testing.

10/17/2006 Online CM 4531030 Examine Torque Switch N/A N/A No impact on LLRT or PIV testing.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 82 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) I -Date I Outage I Work Order I Work Order Description I AF Tests I AL Tests Comments 10/18/2006 Online CM 4531090 Replace Motor Pinion N/A N/A No impact on Gear LLRT or PIV testing.

Fall/2006 RE23 CM Packing Leak; No AL LLRT: PIV: No impact on 4537229: LLRT required due to 17.5 scfh (< 50 scfh) 0 gpm (< 5 gpm) LLRT or PIV minimal packing/seat load testing.

change. Monitoring LLRT; assume 1st periodic test for PIV.

04/18/2007 Online PM 4485530 Examine MO-Elec N/A N/A No impact on PM 4498698 Examine MO LLRT or PIV testing.

Spring/2008 RE24 CM 4632406 Repack valve LLRT: N/A No impact on CM 4631163 Adjust Packing/Viper Test 32.14 scfhi (< 50 LLRT or PIV CM 4531210 Refurbed AO; scfh) testing.

No AL LLRT/PIV PIV: Monitoring required due to minimal 0.0544 gpm (< 5 LLRT; 2nd packing/seat load change. gpm) periodic test for PIV.

10/14/2008 N/A PM 4600595 Clean and Lubricate Stem N/A N/A No impact on LLRT or PIV testing.

Fall/2009 RE25 N/A N/A LLRT: N/A Monitoring 12.74 scflh (< 50 LLRT; 3rd scfh) periodic test PIV: for PIV.

0.054 gpm (< 5gpm) 07/13/2010 Online PM 4664227 Examine MO-Elec N/A N/A No impact on PM 4664250 Examine MO-Mech LLRT or PIV testing.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Pare 83 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage I Work Order Work Order Description AF Tests AL Tests Comments Spring/2011 RE26 N/A N/A LLRT: N/A Monitoring 23.16 scfh (< 50 LLRT (1 st scffi) periodic test);

PIV: 4th periodic 0.136 gpm (< 5 test for PIV.

gpm) 07/19/2011 Online PM 4749837 Clean and Lubricate Stem N/A N/A No impact on LLRT or PIV testing.

Fall/2012 RE27 CM 4842207 Viper diagnostic test; No LLRT: N/A No impact on AL LLRT/PIV required 0.17 scfh (< 50 scfl) LLRT or PIV due to minimal seat load testing.

change. Monitoring LLRT (2nd periodic test);

No PIV test due to approved PIV relief request.

01/14/2013 Online PM 4864090 Examine MO-Mech N/A N/A No impact on PM 4864089 Examine MO-Elec LLRT or PIV testing.

01/16/2014 Online CM 4996016 Reterminate Motor Wiring N/A N/A No impact on LLRT or PIV testing.

Fall/2014 RE28 N/A N/A N/A N/A No tests due to Option B /

approved PIV relief request.

01/12/2015 Online PM 4953672 Clean and Lubricate stem N/A N/A No impact on LLRT or PIV testing.

AF= As Found AL= As Left CM = Corrective Maintenance PM= Preventive Maintenance

NLS2015026 Page 84 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date I Outage I Work Order Work Order Description I AF Tests AL Tests Comments RHR-MOV- Spring/2005 RE22 RHR-MO- Examine Motor Operator LLRT: N/A No impact on M0274A M0274A 7.5 scfhi (< 35 scflh) LLRT or PIV

& PM 4363586 PIV: testing.

RHR-CV-26CV 0.1224 gpm (< 5 (Test #3) gpm)

Fall/2006 RE23 RHR-MOV- Evaluate Packing - Adjust LLRT: LLRT: Routine PM M0274A: or Repack - Repacked 0.75 scfi (< 35 scfh) 4.7 scfh (< 35 scfh)

PM 4446728 valve PIV:

0.041 gpm (< 5 gpm)

RHR-MO- Examine Motor Operator M0274A PM 4446878 Spring/2008 RE24 N/A N/A LLRT: N/A Assume 1st 4.27 scfh (< 35 scflh) periodic test PIV: for LLRT 0.054 gpm (< 5 (and PIV) gpm) test.

Fall/2009 RE25 RHR-MO- Examine MO-Mech LLRT: N/A No impact on M0274A 8.31 scffi (< 35 scfh) LLRT or PIV PM 4645290 PIV: testing. 2nd 0.082 gpm (< 5 periodic test RHR-CV- Adjust Reed Switches gpm) for LLRT 26CV (and PIV)

CM 4723494 test.

Spring/2011 RE26 RHR-MOV- Evaluate Packing - Adjust N/A PIV: No impact on M0274A: or Repack - Tightened 0.082 gpm (< 5 gpm) PIV test.

PM 4744619: Packing LLRT no longer required due to closed loop analysis. 3rd periodic test for PIV test.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 85 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Fall/2012 RE27 RHR-CV- Repack Valve; performed N/A N/A No PIV test 26CV: exercise test and no due to PM 4848060 external leakage at approved PIV pressure as PMT; PIV test relief request.

not required as had no impact to seating ability and located inside Drywell.

RHR-CV- Adjust Limit Switch 26CV:

CM 4918074 RHR-MO- Examine MO-Mech M0274A:

PM 4848151 Fall/2014 RE28 N/A N/A N/A N/A No PIV test due to approved PIV relief request.

RHR-MOV- Spring/2005 RE22 RHR-MO- Refurbish MO LLRT: LLRT: AF - AL M0274B M0274B Examine MO 9.6 scfh (< 35 scfh) 9.4 scfh (< 35 scfh) LLRT.

& CM 4299766 PIV:

RHR-CV-27CV PM 4363585 0.136 gpm (< 5 gpm)

(Test #4) Fall/2006 RE23 RHR-MOV- Evaluate Packing - Adjust LLRT: PIV: No impact on M0274B or Repack - No packing 9.8 scth (< 35 scfh) 0.109 gpm (< 5 gpm) LLRT or PIV PM 4446729 adjustment required. testing.

Examine MO PM 4446875 Spring/2008 RE24 RHR-CV- Repacked Valve LLRT: LLRT: Assume 27CV: 14.5 scth (< 35 scth) 28.59 scfh (< 35 scfh) resets LLRT PM 4541360 PIV: frequency.

0.163 gpm (< 5 gpm)

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 86 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Fall/2009 RE25 RHR-MO- Examine MO-Mech LLRT: N/A No impact on 274B: 15.7 scfth (< 35 scflh) LLRT or PIV PM 4645289 PIV: tests.

0.218 gpm (< 5 Assume 1st gpm) periodic test for LLRT and PIV test.

Spring/201 1 RE26 RHR-MOV- Evaluate Packing - Adjust N/A PIV: LLRT no M0274B: or Repack - Tightened 0.326 gpm (< 5 gpm) longer PM 4744620 packing required due to closed loop analysis. No impact on PIV test; 2nd periodic PIV test.

Fall/2012 RE27 PM 4848150 Examine MO-Mech N/A N/A No PIV test due to approved PIV relief request.

Fall/2014 RE28 N/A N/A N/A N/A No PIV test due to approved PIV relief request.

RHR-MOV-MO17 Spring/2005 RE22 PM 4363507 Examine MO and Verify LLRT: No impact on (Test #5) Indication 2.95 scfli (< 30 scfh) LLRT or PIV PIV: testing.

PM 4363526 Examine MO 0.027 gpm (< 5 Assume 1st gpm) periodic test for LLRT and PIV.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 87 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Fall/2006 RE23 PM 4446718 Clean and Lube Stem LLRT: No impact on CM 4535994 Perform Motor Pinion 1.75 scfh (< 30 scfh) LLRT or PIV Inspection PIV: testing. 2nd 0 gpm (< 5 gpm) periodic test for LLRT and PIV.

Spring/2008 RE24 CM 4546759 Replace MO and LLRT: PIV: No impact on diagnostic test; AL LLRT 0.68 scth (< 30 scfli) 0 gpm (< 5 gpm) LLRT or PIV not required due to testing. 3rd minimal change in seat periodic test load. for LLRT and PIV.

Fall/2009 RE25 PM 4645142 Clean and Lubricate PIV: LLRT not 0 gpm (< 5 gpm) required due to Option B; 4th periodic PIV test.

Spring/2011 RE26 PM 4744696 Examine MO - Mech PIV: LLRT not CM 4740307 Motor Pinion Inspection 0.027 gpm (< 5 required due PM 4744691 Examine MO - Elect gpm) to Option B; 5th periodic PIV test.

Fall/2012 RE27 PM 4848600 Examine MO LLRT: No PIV test 5.32 scfb (< 30 scfth) due to approved PIV relief request.

Fall/2014 RE28 PM 4983676 Examine MO N/A No tests due to Option B /

PIV relief request.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 88 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) I -Date I Outage I Work Order I Work Order Description [ AF Tests I AL Tests Comments RHR-MOV-MO 18 Spring/2005 RE22 PM 4363506 Examine MO and Verify LLRT: LLRT: Assume (Test #6) Indication 1.96 scfh (< 30 scfh) 2.06 scfli (< 30 scffh) resets LLRT PIV: frequency.

CM 4212544 Refurb MO and diagnostic 0.0408 gpm (< 5 test gpm)

PM 4363568 Examine MO Fall/2006 RE23 PM 4446727 Evaluate Packing Adjust LLRT: PIV: No impact on or Repack - (tightened 2 2.6 scflt (< 30 scfth) 0.109 gpm (< 5 gpm) LLRT or PIV flats); AL LLRT not testing. 1st required due to minimal periodic test change in packing and for LLRT and seating forces. PIV.

PM 4446867 Examine Motor Operator PM 4446860 Examine MO and Verify Indication Spring/2008 RE24 PM 4549525 Examine Motor Operator LLRT: No impact on 0.7 scfh (< 30 scfh) LLRT or PIV CM 4531750 Motor Pinion Gear PIV: testing. 2nd Inspection 0.109 gpm (< 5 periodic test gpm) for LLRT and PIV.

Fall/2009 RE25 CM 4640553 Motor Pinion Gear LLRT: PIV: LLRT no Inspection N/A 0.218 gpm (< 5 gpm) longer required due to closed loop analysis. No impact on PIV test. 3rd periodic PIV test.

AF = As Found AL = As Left CM Corrective Maintenance PM= Preventive Maintenance

NLS2015026 Page 89 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Spring/2011 RE26 PM 4744618 Evaluate Packing Adjust LLRT: PIV: No impact on or Repack - (1 flat): N/A 0.027 gpm (< 5 gpm) PIV test. 4th periodic PIV PM 4746148 Examine MO-Mech test.

PM 4744690 Examine MO-Elec Fall/2012 RE27 PM 4848601 Examine MO-Mech N/A N/A No impact on PIV test. No PIV test due to approved PIV relief request.

Fall/2014 RE28 CM 4945389 Viper Test - no torque N/A N/A No PIV test switch or packing due to adjustments required approved PIV (AF=AL); PIV not relief request.

required PM 4949440 Evaluate Packing Adjust or Repack - Not needed PM 4950106 Examine MO (Mech/Elec)

CS-MOV-MO12A Spring/2005 RE22 N/A N/A LLRT: N/A Periodic (Test #7) 0.004 scfh (< 10 LLRT and scfhi) PIV test.

PIV: Assume 1st 0.299 gpm (< 5 periodic PIV gpm) test.

08/02/2005 Online PM 4387217 Clean, Lubricate, Partial N/A N/A No impact on Stroke LLRT or PIV testing.

08/02/2006 Online CM 4447691 Adjust Packing (tightened N/A N/A No impact on 2 flats); no AL LLRT/PIV LLRT or PIV required. testing.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 90 of 99 2

90 of 99 Attachment NLS2015026 Page Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) I -Date Outage I Work Order Work Order Description [ AF Tests I AL Tests I Comments Fall/2006 RE23 CM 4531453 Motor Pinion Gear N/A PIV: No impact on Inspection 0.435 gpm (< 5 gpm) LLRT or PIV testing.

LLRT not required due to option B.

2nd periodic PIV test.

02/05/2008 Online PM 4532685 Examine MO - Mech N/A N/A No impact on LLRT or PIV testing.

Spring/2008 RE24 CM 4547083 Refurb and test MO LLRT: LLRT: AF-AL 0.86 scfh (< 10 scflh) 1.05 scffi (< 10 scfh) LLRT. No PIV: impact on CM 4561197 Install ETT/QSS 0.19 gpm (< 5 gpm) LLRT or PIV testing. 3rd periodic PIV test.

Fall/2009 RE25 CM 4723418 Adjust close limit switch PIV: N/A No impact on 0 gpm (< 5 gpm) LLRT or PIV testing.

LLRT not required due to option B.

4th periodic PIV test.

Spring/2011 RE26 N/A N/A PIV: N/A LLRT not 0 gpm (< 5 gpm) required due to option B.

5th periodic PIV test.

08/10/2011 Online I PM 4749833 Clean, Lubricate, and N/A N/A No impact on Partial Stroke LLRT or PIV testing.

AF= As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 91 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Fall/2012 RE27 PM 4848626 Examine MO (Mech & LLRT: N/A No impact on Elec); 0.1528 scflh (< 10 LLRT or PIV scfh) testing. 6th PIV: periodic PIV 0 gpm (< 5 gpm) test.

Fall/2014 RE28 CM 4945454 Viper Test; AL LLRT/PIV LLRT: No impact on tests not required due to 1.1 scflh (< 10 scfh) LLRT or PIV PM 4950123 minimal change in testing. PIV packing and seating test not forces. required due to approved Examine MO (Clean/Lube relief request.

Stem)

CS-MOV-MO12B Spring/2005 RE22 N/A N/A LLRT: N/A Periodic (Test #8) 1.23 scflt (< 10 scfh) LLRT and PIV: assume 1st 0 gpm (< 5 gpm) periodic PIV test.

08/14/2006 Online PM 4465037 Clean/Lube/Partial Stroke N/A N/A No impact on LLRT or PIV CM 4334765 Periodic Diagnostic Test; testing.

no AL LLRT/PIV Fall/2006 RE23 CM 4534089 Motor Pinion Gear PIV: N/A No impact on Inspection 0 gpm (< 5 gpm) LLRT or PIV testing.

LLRT not required due to option B.

2nd periodic PIV test.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 92 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Spring/2008 RE24 CM 4561198 Install ETT/QSS PIV: N/A No impact on 0.082 gpm (< 5 LLRT or PIV gpm) testing.

LLRT not required due to option B.

3rd periodic PIV test.

Fall/2009 RE25 PM 4658094 Examine & Clean LLRT: N/A No impact on Operator 1.67 scfh (< 10 scfh) LLRT or PIV PIV: testing. 4th 0 gpm (< 5 gpm) periodic PIV test.

11/12/2009 Online PM 4625209 Clean/Lube/Partial Stroke N/A N/A No impact on LLRT or PIV testing.

Spring/20 11 RE26 PM 4767601 Examine Motor Operator PIV: N/A No impact on 0 gpm (< 5 gpm) LLRT or PIV testing.

LLRT not required due to option B.

4th periodic PIV test.

Fall/2012 RE27 CM 4840074 Viper Test LLRT: LLRT: No impact on 1.82 scfi (< 10 scfth) 2.02 scfh LLRT or PIV PM 4848541 Examine MO (Mech/Elec) PIV: testing. 5th 0.0136 gpm (< 5 periodic PIV I gpm) test.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 93 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Fall/2014 RE28 PM 4950054 Examine MO (Clean/Lube N/A N/A No impact on Stem) LLRT or PIV testing. No LLRT test performed due to option B and no PIV test performed due to an approved relief request.

CS-CV-18CV Spring/2005 RE22 N/A N/A PIV: N/A LLRT not (Test #9) 0.3264 gpm (< 5 required due gpm) to Option B; periodic PIV test.

Fall/2006 RE23 N/A N/A PIV: N/A LLRT not 0.326 gpm (< 5 required due gpm) to Option B; periodic PIV test.

Spring/2008 RE24 N/A N/A LLRT: N/A Periodic 1.19 scfh (< 15 scfh) LLRT and PIV: PIV tests.

0.136 gpm (< 5 gpm)

Fall/2009 RE25 PM 4645121 Repack Valve LLRT: LLRT (Final AL): Significant CM 4724012 Disassemble and Repair 0.131 scfh (< 15 0.79 scfhi (< 15 scfh) Maint. Resets following issues during scfh) PIV: LLRT/PIV repack 0 gpm (< 5 gpm) frequency.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 94 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Spring/2011 RE26 N/A N/A PIV: N/A LLRT no 0 gpm (< 5 gpm) longer required due to closed loop analysis.

First periodic PIV test.

Fall/2012 RE27 N/A N/A PIV: N/A Second 0 gpm (< 5 gpm) periodic PIV test.

Fall/2014 RE28 N/A N/A N/A PIV test not required due to approved relief request.

CS-CV-19CV Spring/2005 RE22 N/A N/A LLRT: N/A Periodic (Test #10) 0.95 scfli (< 15 scfth) LLRT and PIV: PIV tests.

0 gpm (< 5 gpm)

Fall/2006 RE23 N/A N/A PIV: N/A LLRT not 0 gpm (< 5 gpm) required due to Option B; periodic PIV test.

Spring/2008 RE24 CM 4631924 Adjust/add packing LLRT: LLRT (Final AL): Elected to PM 4541346 Repack valve 0.65 scfth (< 15 scfth) 1.4 scfh Reset PIV (Final AL): LLRT/PIV 0.05 gpm (< 5 gpm) frequency.

Fall/2009 RE25 N/A N/A LLRT: N/A First periodic 1.37 scfh (< 15 scfli) LLRT and PIV: PIV test.

0 gpm (< 5 gpm)

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 95 of 99 Relief Request RV-05: Table 1: Maintenance and PIV/LLRT Test History Since 01/01/2005 Component(s) -Date Outage Work Order Work Order Description AF Tests AL Tests Comments Spring/2011 RE26 N/A N/A PIV: N/A LLRT no 0 gpm (< 5 gpm) longer required due to closed loop analysis.

Second periodic PIV test.

Fall/2012 RE27 N/A N/A N/A N/A No PIV test required due to approved relief request.

Fall/2014 RE28 N/A N/A N/A N/A No PIV test required due to approved relief request.

AF = As Found AL = As Left CM = Corrective Maintenance PM = Preventive Maintenance

NLS2015026 Page 96 of 99 Relief Request RG-01 ASME OM Code Test Frequencies Proposed Alternative in Accordance with 10 CFR 50.55a(h)(3)(z)(2)

Hardship or Unusual Difficulty without a Compensating Increase in Level of Quality and Safety

1. ASME Code Component(s) Affected All Pumps and Valves contained within the Inservice Testing Program (IST) scope.
2. Applicable Code Edition and Addenda ASME OM Code 2004 Edition through 2006 Addenda
3. Applicable Code Reauirement This request for relief applies to the frequency specification of the ASME OM Code for all pump and valve testing contained within the IST Program scope. The applicable ASME OM Code (2004 Edition through the 2006 Addenda) sections include the following:

Code Paragraph Description The frequency for inservice testing shall be in accordance with the ISTA-3 120(a) requirements of Section IST ISTB-3400 Frequency of Inservice Tests ISTB-6200 Corrective Action ISTC-3510 Exercising Test Frequency ISTC-3540 Manual Valves ISTC-3560 Fail-Safe Valves ISTC-3630(a) Frequency ISTC-3700 Position Verification Testing At least one valve from each group shall be disassembled and examined ISTC-522 1(c)(3) at each refueling outage; all valves in a group shall be disassembled and examined at least once every 8 years.

ISTC-5222 Condition-Monitoring Program ISTC-5230 Vacuum Breaker Valves ISTC-5240 Safety and Relief Valves ISTC-5260 Explosively Actuated Valves Appendix I*, 1-1320 Test Frequencies, Class 1 Pressure Relief Valves Appendix I, 1-1330 Test Frequency, Class I Nonreclosing Pressure Relief Devices Test Frequency, Class I Pressure Relief Valves That Are Used for Thermal Relief Applications Appendix I, 1-1350 Test Frequency, Classes 2 and 3 Pressure Relief Valves Appendix I, 1-1360 Test Frequency, Classes 2 and 3 Nonreclosing Pressure Relief Devices Appendix I, 1-1370 Test Vle Frequency, Classes 2 and 3 Primary Containment Vacuum Relief Valves Test Frequency, Classes 2 and 3 Vacuum Relief Valves, Except for Primary Containment Vacuum Relief Valves

NLS2015026 Page 97 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)

Code Paragraph Description Test Frequency, Classes 2 and 3 Pressure Relief Devices that are Used for Thermal Relief Application.

Appendix II**, II- Performance Improvement Activities 4000(a)

Appendix II, II- Optimization of Condition-Monitoring Activities 4000(b)

  • Appendix I is for Pressure Relief Devices
    • Appendix II is for the Check Valve Condition Monitoring Program (CVCM)
4. Reason for Request Pursuant to 10 CFR 50.55a, "Codes and Standards," paragraph (h)(3)(z)(2), relief is requested from the frequency specification of the ASME OM Code. The basis of the Relief Request is that the Code requirement presents an undue hardship without a compensating increase in the level of quality and safety.

The ASME OM Code, 2004 Edition through the 2006 Addenda, establishes the inservice test frequency for all components within the scope of the Code. The frequencies (e.g., quarterly) have always been interpreted as "nominal" frequencies (generally as defined in Table 3.2 of NUREG 1482, Revision 2) and if necessary, owners applied the surveillance extension time period (i.e.

grace period) contained in the plant Technical Specifications (TS) SRs. The CNS TS SR 3.0.2 states that the specified frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency. This would allow an extension of up to 25% of the surveillance test interval to accommodate plant conditions that may not be suitable for conducting the surveillance. However, regulatory issues have been raised concerning the applicability of the TS grace period to ASME OM Code required inservice test frequencies.

The lack of a tolerance band (grace period) on the ASME OM Code IST frequency restricts operational flexibility. There may be a conflict where an IST test could be required (i.e., its frequency could expire), but it is not possible or not desired that it be performed until sometime after a plant condition or associated TS is applicable. Therefore, to avoid this conflict, the IST test intervals should be allowed to be extended by up to 25%.

Thus, just as with TS required surveillance testing, some tolerance is needed to allow adjusting OM Code testing intervals to suit the plant conditions and other maintenance and testing activities. This assures operational flexibility when scheduling IST tests that minimize the conflicts between the need to complete the test and plant conditions.

5. Proposed Alternative and Basis for Use Code Case OMN-20 is included in the ASME OM Code, 2012 Edition, and will be used as an alternative to the frequencies of the ASME OM Code. The requirements of Code Case OMN-20 are described below.

NLS2015026 Page 98 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)

ASME OM, Division 1, Section IST and all earlier editions and addenda specify component test frequencies based either on elapsed time periods (e.g., quarterly, 2 year, etc.) or the occurrence of plant conditions or events (e.g., cold shutdown, refueling outage, upon detection of a sample failure, following maintenance, etc.).

(a) Components whose test frequencies are based on elapsed time periods shall be tested at the frequencies specified in Section IST with a specified time period between tests as shown in Table

1. The specified time period between tests may be reduced or extended as follows:

(1) For periods specified as fewer than 2 years, the period may be extended by up to 25% for any given test.

(2) For periods specified as greater than or equal to 2 years, the period may be extended by up to 6 months for any given test.

(3) All periods specified may be reduced at the discretion of the owner (i.e., there is no minimum period requirement).

Period extension is to facilitate test scheduling and considers plant operating conditions that may not be suitable for performance of the required testing (e.g., performance of the test would cause an unacceptable increase in the plant risk profile due to transient conditions or other ongoing surveillance, test, or maintenance activities). Period extensions are not intended to be used repeatedly merely as an operational convenience to extend test intervals beyond those specified.

Period extensions may also be applied to accelerated test frequencies (e.g., pumps in alert range) and other fewer than 2 year test frequencies not specified in Table 1.

Period extensions may not be applied to the test frequency requirements specified in Subsection ISTD, Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants, as Subsection ISTD contains its own rules for period extensions.

(b) Components whose test frequencies are based on the occurrence of plant conditions or events may not have their period between t ests extended except as allowed by ASME OM, Division 1, Section IST, 2009 Edition through OMa-20 11 Addenda and all earlier editions and addenda.

NLS2015026 Page 99 of 99 Relief Request RG-01 ASME OM Code Test Frequencies (continued)

Table 1 Specified Test Frequencies Frequency Specified Time Period Between Tests Quarterly 92 days (or every 3 months)

Semiannually 184 days (or every 6 months)

Annually (or every year) 366 days x years x calendar years where x is a whole number of years > 2

6. Duration of Proposed Alternative This proposed alternative will be utilized for the entire fifth ten-year interval.
7. Precedents This relief request was previously approved for the Fermi-2 third ten-year interval as Relief Request PVRR-001 (TAC No. MF2967, dated July 16, 2014).

Three Mile Island Nuclear Station, Unit 1 - Relief Requests PR-01, PR-02, and VR-02, Associated With The Fifth 10-Year Inservice Test Interval (TAC Nos. MF0046, MF0047 and MF0048, dated August 15, 2013).

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