SVPLTR 13-0020, Written Response to Preliminary White Finding from NRC Integrated Inspection Report 2013-002

Written Response to Preliminary White Finding from NRC Integrated Inspection Report 2013-002

ML13169A055
Person / Time
Site:	Dresden
Issue date:	06/06/2013
From:	Czufin D Exelon Generation Co
To:	Document Control Desk, NRC/RGN-III
References
SVPLTR: #13-0020, EA-13-079 IR-13-002
Download: ML13169A055 (14)

Text

Dresden Nuclear Power Station 6500 North Dresden Road Exelon Generation. Morris. IL 60450 815 942 2920 Telephone www.exeloncorp.com SVPLTR: #13-0020 June 6, 2013 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Dresden Nuclear Power Station, Units 2 and 3 Renewed Facility Operating License Nos. DPR-19 and DPR-25 NRC Docket Nos. 50-237 and 50-249

Subject:

Dresden Nuclear Power Station Written Response to Preliminary White Finding from NRC Integrated Inspection Report 2013-002

Reference:

1. Letter from S. A. Reynolds (NRC) to M. J. Pacilio (Exelon Generation Company, LLC (EGC)), "Dresden Nuclear Power Station, Units 2 and 3, Integrated Inspection Report 05000237/2013002, 05000249/2013002; Preliminary White Finding," dated May 7, 2013

2. Letter from D. Czuf in (EGC) to J. Cameron (NRC), "Dresden Nuclear Power Station Response to Preliminary White Finding from NRC Integrated Inspection Report 2013-002," dated May 17, 2013 In Reference 1, the NRC identified a preliminary White finding concerning Dresden Nuclear Power Station's (DNPS's) external flooding strategy. Specifically, that Dresden Abnormal Operating Procedure, DOA 0010-04, "Floods," did not contain steps directing operators to maintain reactor vessel inventory during a probable maximum flood (PMF) event when a reasonable simulation of this procedure was executed in August 2012.

Reference 1 provided EGC an opportunity to present its perspectives on the facts and assumptions used by the NRC to arrive at the finding and its significance at either a Regulatory Conference or in a written response to the NRC. In Reference 2 EGC notified the NRC of its intent to provide a written response on the finding. Attachment 1 provides EGC's written response to the preliminary White finding identified in Reference 1. Attachments 2 and 3 provide additional data and describe research methodologies to support EGC's response.

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June 6, 2013 US NRC Page 2 This letter does not contain any new regulatory commitments. Should you have any questions concerning this letter, please contact Mr. Hal Dodd, DNPS Regulatory Assurance Manager, at (815) 416-2800.

Respectfully, David M. Czuf in Site Vice President Dresden Nuclear Power Station Attachments:

1. EGC Response to Preliminary White Finding

2. LER Research Methodology

3. Additional RPV Make-up Injection Methods cc: Regional Administrator, NRC Region III NRC Senior Resident Inspector, Dresden Nuclear Power Station Chief, Division of Reactor Projects Branch 6, NRC Region III

Attachment 1 Exelon Generation Company, LLC Response to Preliminary White Finding NRC Finding Summary Preliminary White: The inspectors identified a finding and an associated Apparent Violation (AV) of Technical Specification (TS) Section 5.4.1. Technical Specification 5.4.1 requires, in part, that written procedures be established, implemented, and maintained covering the following activities: "the applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978." RG 1.33, Revision 2, Appendix A, Paragraph 6 addresses "Procedures for Combating Emergencies and Other Significant Events" and Item w addresses "Acts of Nature (e.g ., tornado, flood, dam failure, earthquakes)." From February 20, 1991, to November 21, 2012, the licensee failed to establish a procedure addressing all of the effects of an external flooding scenario on the plant. Specifically, DOA 0010-04, "Floods," did not account for reactor vessel inventory make up during an external flooding scenario up to and including the probable maximum flood event which could result in reactor vessel water level lowering below the top of active fuel. This finding does not represent an immediate safety concern in that the licensee now has procedures for providing reactor vessel make up water during an external flood scenario up to and including a PMF event.

The inspectors determined that the licensee's failure to consider reactor vessel inventory make up during an external flooding scenario up to and including the PMF was a performance deficiency warranting a significance evaluation. The finding was determined to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," dated September 7, 2012, because it was associated with the Mitigating Systems Cornerstone attribute of procedure quality and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. A Significance and Enforcement Review Panel (SERP), using IMC 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria," dated April 12, 2012, preliminarily determined the finding to be of low to moderate safety significance (White). The inspectors determined that this finding has a cross-cutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, Self and Independent Assessments, since it involves the failure to identify the lack of procedural steps to address a critical function during a comprehensive self assessment of the flooding strategy. (P.3(a)) (Section 40A2)

NRC Baseline Significance Determination Process Review As part of that process, the Region III Senior Reactor Analyst (SRA) developed a simple event tree model to perform a bounding quantitative evaluation. The model represents an external flood event that exceeds grade level elevation (517.5') and requires implementation of the flood procedure, DOA 0010-04, "Floods," Revision 32.

Exelon Generation Company (EGC) Response EGC agrees that a performance deficiency existed in that DOA 0010-04, "Floods," did not provide a procedurally directed method for reactor pressure vessel (RPV) inventory make up during an external flooding scenario up to and including the probable maximum flood event during the time that the site is inundated with flood waters. EGC has identified and incorporated into procedures multiple methods to provide RPV inventory make up during an external flood.

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Attachment 1 Exelon Generation Company, LLC Response to Preliminary White Finding Review of the NRC Significance Determination A Significance and Enforcement Review Panel (SERP) determined that IMC 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria," dated April 12, 2012, was appropriate to use due to the lack of existing quantitative SDP tools for evaluating external flooding risk. As part of that process, the Region III Senior Reactor Analyst (SRA) developed a simple event tree model to perform a bounding quantitative evaluation. The model represents an external flood event that exceeds grade level elevation (517.5') and requires implementation of the flood procedure, DOA 0010-04, "Floods," Revision 32.

The input assumptions were highly uncertain and were varied to calculate a range of risk estimates. The values for flood frequency, the probability of reactor pressure vessel leakage requiring makeup, and the likelihood of successful makeup to the vessel during and after the flood recedes were key inputs to the evaluation. EGC requests that additional consideration is taken based on additional information that is being provided in this submittal. There are two key aspects that may influence the final safety significance determination. First, the probability of RPV leakage requiring makeup during a flood, and secondly, the probabilities that RPV makeup would be successful during and after the flood.

Probability of RPV leakage requiring makeup during a flood EGC originally provided information to the SRA that included 15 years of DNPS-specific primary system leakage information. Table 1 below provides DNPS, Units 2 and 3 monthly maximum, minimum, and average total reactor coolant system (RCS) leakage data over the past 15 years.

Table 1: Total RCS Leakage Values for DNPS from 1998 to 2013 Total RCS Leakage Unit 2 (gpm) Unit 3 (gpm)

Maximum 4.547 4.752 Minimum 1.455 1.535 Average 2.162 2.039 This information was provided to aid in determination of reasonable and realistic quantity of RPV makeup that would be required during a flood. In addition, an engineering evaluation was performed which showed that expected leakage rates would be substantially lower after reactor pressure was reduced to comply with the plant shut down requirements of DOA 0010-04.

Subsequently, EGC has performed two separate industry reviews on boiling water reactor (BWR) RPV leakage data. The first review was to identify abnormal peaks of RPV leakage.

This review was performed by searching industry events related to unacceptable RPV leakage, specifically Licensee Event Reports (LERs) representing 25 years of reactor operation. The second review was to determine day-to-day RPV leakage utilizing all available industry reporting data, which shows quarterly average Boiling Water Reactors (BWR) RPV leakage representing 15 years of reactor operation. These industry reviews provide a much broader range of Page 2 of 5

Attachment 1 Exelon Generation Company, LLC Response to Preliminary White Finding operational conditions and they provide a more thorough and comprehensive basis in determining realistic leakage values and probabilities.

LER Review - The results of the LER review identified two examples of leakage abnormally high relative to other available industry data. Both of these examples occurred greater than 15 years ago and were related to reactor recirculation pump seal failures. One event (LER 245-89014-1) resulted in improvements in the maintenance and monitoring of seals. The second event (LER 461-96010) documented non-conservative operations in response to a reactor recirculation seal leak and served as a basis for multiple industry notification publications outlining the importance of conservative decision making. These events are anomalous relative to the remaining industry data based upon the age of the events (greater than 15 years), subsequent industry improvements in seal reliability, and the adoption of conservative decision making principles as an industry standard. Based on the removal of the outliers, the average LER review total leakage is 4.74 gpm with a standard deviation of 4.461 gpm. LER review methodology is provided in Attachment 2.

The LER data indicates that operational leakage is typical less than the allowed values specified in the plant technical specification. Any excessive leakage that would be experienced would be thoroughly investigated and appropriate actions implemented.

Industry Operating Data - The industry reporting data review for the last 15 years (extent of available data) identified an average high total drywell leakage of approximately 5.82 gpm with a standard deviation of 1.182 gpm. The overall BWR average total drywell leakage for the previous 15 years is approximately 2.5 gpm.

A statistical analysis was performed to determine the probability that RPV leakage would be less than 5 gpm and less than 10 gpm. The results of this analysis indicate that the pre-existing RCS leakage to the drywell has a high probability of being less than 5 gpm (approximately 98 percent) and approximately a 99.97 percent probability that the drywell leakage would be less than 10 gpm.

Based upon the results of the analysis and DNPS-specific RCS leakage data in conjunction with the comprehensive LER and industry data review, EGC has high confidence that RPV inventory makeup requirements to account for leakage losses during a flooding event would be less than 5 gpm.

Probability that RPV makeup would be successful during and after the flood In November of 2012, a DNPS senior reactor operator (SRO) developed a simple method to add water to the RPV utilizing the standby liquid control (SBLC) system while reviewing follow up questions from the NRC related to the flood mitigation procedure. In November of 2012, this method was incorporated into Technical Support Guidelines (TSG) -3, "Operational Contingency Action Guidelines," which is referenced in DOA 0010-04, "Floods.".

A former DNPS SRO, who is also a current member of the DNPS Emergency Response Organization (ERO), was asked to identify additional options for adding makeup to the DNPS, Unit 2 and 3 RPVs utilizing their plant knowledge and plant drawings. The former SRO Page 3 of 5

Attachment 1 Exelon Generation Company, LLC Response to Preliminary White Finding identified several options in less than two hours. A second individual, who holds a current SRO license and is also a member of the ERO, performed an independent review of the methods that had been identified. These options, including marked-up plant drawings, were presented to a non-licensed operator to perform plant walkdowns to validate feasibility, availability of required equipment, and difficulty of implementation.

Three of the methods identified were physically walked down in the plant to verify that tools, equipment, labeling, accessibility, and complexity would support implementation with a moderate to high level of confidence.

These walkdowns identified that the methods were simple to implement and were well within the knowledge, skill, and capability of the operators. Each connection was on the same elevation and in relatively close proximity to the available injection source. For example a core spray injection path is within approximately 25 ft and the same line of sight of the injection source.

The connections are standard type connections that are readily available and routinely used by plant personnel.

The review also verified that the injection paths involved the operation of components that are periodically operated by plant personnel to perform similar filling evolutions and were governed by plant procedures. The following are procedures that govern those tasks:

• Core Spray injection path o DOS 7100-10 HIGH PRESSURE SEAT LEAKAGE TESTING OF CORE SPRAY INJECTION VALVES 2(3)-1402-9A(B) and 2(3)-1402-25A(B)

" Isolation Condenser injection path o DOP 1300-11 UNIT 2 ISOLATION CONDENSER FILL AND VENT o DOP 1300-10 UNIT 3 ISOLATION CONDENSER FILL AND VENT

• Instrument Line Backfill o DIS 0500-04, Reactor Process Instrument Line Excess Flow Check Valve Operational Test.

To perform these methods, the following basic steps must be accomplished for each of the injection points identified:

" Attach a standard quick connect (i.e., Chicago style) fitting to the injection system drain line and if require, a quick connect may also be attached to the water source piping.

• Attach a hose between the injection system and the fire hose drain line (or any other available water source)

" Open the fire hose drain line (one valve)

• Open the inboard and outboard drain lines on the injection system The parts required to implement all of these paths are common parts available in large quantities in standard tool locations or various operations storage locations throughout the plant. All of these locations were verified to be elevations above the calculated PMF.

Additionally, all of the paths require the operator to open three valves to commence injection.

The DNPS Senior Resident Inspector was present for these walkdowns to observe the results.

See Attachment 3 for additional information about RPV make-up.

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Attachment 1 Exelon Generation Company, LLC Response to Preliminary White Finding Additionally, this event would require activation and staffing of the ERO when emergency action levels are reached. The ERO staff performs quarterly focus drills and annual exercises that challenge the staff's ability to respond to emergency conditions utilizing standardized problem solving techniques and collective teamwork synergies. These activities in addition to the experience, training, and qualifications of the nuclear station personnel provide EGC confidence that the requisite knowledge, skill, and capability existed not only among the on-shift operations personnel but also among the ERO staff to implement multiple methods to add inventory to the RPV during and after the flood.

EGC has completed a human reliability analysis (HRA) utilizing SPAR-H methodology to aid in the assessment of probability of successfully injecting into the RPV during the flood. Overall results of the HRA indicate that site personnel have adequate knowledge to overcome procedural deficiencies. The necessary tools and parts are easily accessible in a storage area off the turbine floor and reactor building well above peak flood levels. There are tie-in points for the Fire Protection System and primary system connections that are easily assessable. Table top exercises and plant walk downs support the feasibility of injecting water using alternate primary system tie-in points. The calculated Human Error Probability using SPAR-H worksheets is 1.7E-1. This represent an 83 percent success rate for human actions associated with RPV inventory makeup.

Based upon the short time required to identify the multiple methods to establish RPV make-up, the field-validated ease in implementing these actions, the expertise available in the DNPS ERO during a flooding event, and the results of the HRA, EGC concludes that there is a high probability of successfully establishing RPV injection during a PMF event.

Conclusion/Summary EGC agrees that a performance deficiency existed in that DOA 0010-04, "Floods," did not provide a procedurally directed method for reactor vessel inventory make up during an external flooding scenario up to and including the PMF event during the time that the site is inundated with flood waters. EGC has taken actions to identify and correct the causes of the issue.

EGC is requesting that the significance determination be re-evaluated based on the additional information contained in this letter concerning the likelihood that RPV makeup would be required during the flood and reasonable assumptions related to the likelihood that efforts to establish RPV makeup during and after the flood would be successful.

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Attachment 2 Licensee Event Report (LER) Research Methodology LER Research Methodology Based comprehensive search criteria, a search of LERs was performed to include only boiling water reactors (BWRs) This search includes 25 years of LERs.

During the review of the 48 LERs, some of the plants were experiencing higher than normal drywell leakage and took a conservative action to shutdown prior to reaching technical specification limits. Of the LERs reviewed, 6 did not quantify the leakage rates in the LER and are not included in the categories below. The remaining 42 LERs were then categorized based on the following criteria: leakage rates less than or equal to 5 gpm, less than or equal to 10 gpm, less than or equal tol 5 gpm, and greater than 15 gpm.

25 LEts are identified as having reported less or equal to 5 gpm leakage:

9 LERs are identified as having reported less than or equal tol0 gpm leakage:

6 LERs are identified as having reported less than or equal to 15 gpm:

2 LERs are identified as having reported greater than 15 gpm:

All but 2 of the LERs reported leak rates of less than 15 gpm. The 2 LERs identified as being greater than 15 gpm are believed to be anomalies as discussed in Attachment 1. The average leak rates of LERs with unacceptable leakage reporting less than 15 gpm leak rate is 4.74 gpm. The average leak rate for all LERs reported is 6.73 gpm.

Data Analysis:

Average for all LERs (including anomalies) is 6.73 gpm with standard deviation of 10.012 gpm.

Average for LER (anomalies removed) is 4.74 gpm with standard deviation of 4.461 gpm.

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Attachment 2 Licensee Event Report (LER) Research Methodology Below are the 48 LERs that were reviewed based on search criteria:

Highest leakage LER number Year of LER Title rate reported in Event LER (gpm) 387-12007 2012 Unplanned Shutdown due to Unidentified Drywell Leakage 1.1 373-11002 2011 Unit Shutdown Required by Plant Technical Specifications Due to Pressure Boundary Leakage not quantified 461-09004 2009 Steam Leak Due to Valve Packing Torque Results in Required Plant Shutdown 3.4 260-09004-1 2009 Technical Specifications Shutdown Due to Rise in Unidentified Drywell Leakage 3.88 296-07003 2007 Leak In An ASME Class I Code Reactor Pressure Boundary Pipe not quantified 461-07003 2007 IGSCC Causes Pressure Boundary Leak and Reactor Shutdown 2.7 293-07001 2007 Primary Containment Isolations Following a Manual Reactor Scram 0.65 220-06001 2006 Technical Specification Required Shutdown due to Increased Drywell Leakage not quantified 293-03006 2003 Reactor Coolant Pressure Boundary Leakage due to Reactor Vessel Nozzle Weld Crack 3.5 271-03001 2003 Reactor Shutdown Completed for an Increase in Unidentified Leakage Located inside Primary 5.51 249-02006 2002 Reactor Recirculation Loop A Sensing Line Socket Weld Vibration Fatigue Failure not quantified 249-02003 2002 Reactor Recirculation Loop A Sensing Line Socket Weld Vibration Fatigue Failure 0.65 321-02002 2002 Technical Specification Required Plant Shutdown Due to High Unidentified RCS Leakage 6.85 410-01007 2001 Manual Reactor Scram Due to High Unidentified DW Leakage 5.87 249-99003-1 1999 Reactor Recirculation Loop B, High Pressure Flow Element Venturi Instrument Line STM not quantified 397-98015 1998 Discovery Of Reactor Coolant Pressure Boundary Leak During the Shutdown Conditions 0.56 249-97012 1997 Reactor Recirculation B Loop High Pressure Flow Element Venturi Instrument Line STM 0.83 388-97006 1997 Recirculation Discharge Valve Bonnet Vent Line Crack 2 410-97006-1 1997 Plant Shutdown Due To Rising Unidentified Leakage Greater than 10 (Note 1la) 458-97002 1997 Through Wall Linear Indication in a Weld on a Reactor Recirculation System Vent Valve 2 321-97001 1997 Pressure Boundary Leakage Results In Condition Prohibited By Tech Specs 2.4 461-96010 1996 Plant Shutdown Due To Unidentified Reactor Coolant System Leakage From Degraded 48 Reactor Recirculation Pump Seal Greater than Tech Spec Limits 333-95010 1995 Tech Spec Required Plant Shutdown Due To Unidentified Leakage Into Drywell 2.91 410-94007 1994 RPS L_____I Spec and ESF Actuations and a Tech Spec Violation Occurring During Completion of a Tech Required Plant Shutdown 5.47 Page 2 of 4

Attachment 2 Licensee Event Report (LER) Research Methodology Year of Highest leakage LER number Event LER Title rate reported in Evn LER (gpm) 293-93018-1 1993 Completion of a Shutdown Due to Reactor Coolant Pressure Boundary Leakage 3.04 397-91030 1991 Tech Spec Required Plant Shutdown Due to Reactor Pressure Boundary Leakage Through .00026 (Note 2)

Defective Weld on RHR System Drain Line Piping 293-91007 1991 Completion of a Shutdown due to Drywell Floor Sump Leakage Rate and Subsequent Scram 12.2 Signal While Shutdown 410-91006-1 1991 Unusual Event Classification and Reactor Shutdown Due to an Unisolated RCS System 2.9 Boundary Leak 354-90025-1 1990 Recirculation System Instrument Line Crack At Welded Joint Due to Vibration Induced Fatigue 1.5 and a Nonsymmetrically Installed Pipe 220-90016 1990 Unusual Event Classification and Reactor Shutdown Due to Excess Drywell Leakage Resulting Greater than 2 from Unadjusted ERV Pilot Valves (Note lb) 219-90005-1 1990 Tech Spec Required Shutdown Because of Loss of Power to Safety Related Switchgear due to Greater than 5 Grounded Supply Cable (Note 1c) 354-89026-1 1989 Reactor Recirculation System Instrument Line Leakage Results in Mode Change to Cold 0.3 Shutdown as Required by Tech Specs - Equipment Failure Due to Installation Deficiency 245-89014-1 1989 Required Shutdown Due to a Recirculation Pump Seal Failure 45.1 245-89006 1989 Primary Containment Unidentified Leak Rate 2.69 245-88008 1988 Primary Containment Unidentified Leak Rate 2.5 354-88030 1988 Pressure Boundary Leakage of the B Recirculation Pump Discharge Valve and the A not quantified Recirculation Pump Suction Valve Welds 341-88026-1 1988 Plant Shutdown Due to Unidentified Leakage Greater than Allowable Limits 5.4 341-87018 1987 RWCU System Isolation During Troubleshooting and Repair of Steam Leakage 1.7 354-87014 1987 Forced Reactor Shutdown Due to Unidentified Leakage Greater than 5 gpm and Subsequent 5.2 Manual Scram Due to RSCS Rod Block when Shutting Down 458-87002 1987 Manual Reactor Scram due to High Unidentified Drywell Leakage 10.5 Page 3 of 4

Attachment 2 Licensee Event Report (LER) Research Methodology Year of Highest leakage LER number Event LER Title rate reported in LER (gpm) 410-12001-1 2012 Forced Shutdown Due to an Increase in Drywell Leakage in Excess of Technical Specifications 3.7 Limit 410-11002 2011 Reactor Shutdown Due to Reactor Coolant System Unidentified Leakage Above Technical 11.35 Specification Limits 324-11002 2011 Unanalyzed Condition Due to Reactor Pressure Vessel (RPV) Head Detensioned During 10.11 278-05003 2005 Residual Heat Removal System Small Bore Piping Leak due to Weld Deficiency 1 354-05003-01 2005 Reactor Coolant System Leak from Check Valve Position Indicator 14.6 354-05002 2005 Through-Wall Leak on 'B' Reactor Recirculation System Decontamination Port .73 Drywell Floor Drain Leakage in Excess of the 5 GPM Technical 256-89002 1989 Specification Limit Due to a Packing Leak on the Reactor Core Isolation Cooling 5.9 Steam Supply Isolation Valve 397-88029 1988 Plant Shutdown Required by Tech Specs due to High RCS Unidentified Leakage Greater than 5 (Note 1ic)

Note 1: The LERs did not specify a quantity. For the purposes of the averaging, the leak rate was conservatively doubled

a. Categorized below in under "less than 15 gpm", 20 gpm used for average

b. Categorized below in under "less than 5 gpm", 4 gpm used for average

c. Categorized below in under "less than 10 gpm", 10 gpm used for average Note 2: LER reported leak as 20 drops per minute. The conversion used was .000013 gpm equivalent to 1 drop per minute Page 4 of 4

Attachment 3 Additional RPV Make-up Injection Methods Overview The following basic steps must be accomplished for each of the injection points identified:

" Attach a Chicago fitting to the injection system drain line and if require, a quick connect may also be attached to the water source piping.

• Attach a hose between the injection system and the fire hose drain line (or any other available water source)

• Open the fire hose drain line (one valve)

• Open the inboard and outboard drain lines on the injection system The techniques and methods of hooking up hoses to systems with Chicago fittings is one that is performed on a routine basis by Operators to support online maintenance, and more extensively during plant outages. This method is utilized to vent and drain systems when removing them from service.

There are multiple sources of fittings and hoses in the plant. One of the largest supplies located above the 517' elevation is the Unit 1 Hot Tool Crib, which is located adjacent to the Unit 2 Turbine floor. There are also multiple storage containers containing hoses at this same location. The hoses come in 50 foot lengths. The DNPS operators are well versed with removing valve caps and replacing them with Chicago fittings and then connecting hoses to the Chicago fittings. Chicago fittings are universal style couplings. Firmly pressing one coupler to another and twisting the two, seals the connection. Safety clips prevent accidental disconnection during use. This is a convenient quick connect system to mate varying diameters of hose, as all sizes up to 1 inch are interchangeable. A typical Chicago fitting is shown in Figure 1 below.

Figure 1: Typical Chicago Fitting.

All of the alternate injection flow paths identified require installation of a Chicago fitting at the system piping, connecting between 1-2 hoses and opening three manual valves. All of the flow paths have direct paths to the reactor with no automatic isolation valves in the flow path.

For example, the Unit 2 Division 2 Core Spray header has two drain valves located downstream of the last motor operated primary containment isolation valve before the line goes to the reactor vessel. These two valves are in a normally accessible area of the plant and are located between waist and chest height on the 545 ft. elevation. The connection of the hose requires the operator to remove one valve cap and screw on one Chicago fitting to the Core Spray valve 2(3)-1402-33A and connect one 50 foot length (Standard length of hose) of hose between it and a fire hose drain at Fire Hose Station #F65. This fire hose station is similar to the other fire hose stations in the reactor building in that they have a drain valve on it upstream of the hose isolation valve. The fire hose is located on a column approximately 25 feet from the Core Spray valves. The Operator then verifies that either the MOV 2-1402-24B or MOV 2-1402-25B is Page 1 of 3

Attachment 3 Additional RPV Make-up Injection Methods closed in order to prevent the potential backflow of water into the Core Spray piping. These valves are located on accessible catwalks located approximately 10 feet above the 545 feet elevation. Operators are trained, qualified, and routinely operate motor operated valves. The operator then opens the fire hose drain valve and the two valves on the core spray header 2(3)-

1402-32A and the 2(3)-1402-33A. Water then has a direct flow path to the reactor with no automatically operated isolation valves in its path that could inadvertently close. The print below identifies the connection within the core spray system.

"°1'÷o r, Aý wA4~ I.* 2-102CS J70 'C33A

,oaS 2-xUN 2202-Figure 2: P&ID M-27, U-2 Core Spray Piping Available RPV Make-up Sources Below is a list of RPV Make-up sources that have been identified for incorporation into DNPS procedures. The methods utilizing the core spray injection header and isolation condenser have already been incorporated into TSG-3 revision 12.

1. Core Spray Injection Headers (two paths per unit) (2B and 3A paths included in TSG-3 Rev 12)

• Connect a hose to the fire header supplied by the flood pump to the drain valves downstream of the 2(3)- 1402-25A or the 2(3)-i402-25B.

2. Backfill Instrument lines at Instrument Racks 2202(3)-5 or 6 (two paths per unit)

• Connect a hose to the rack drain line and inject through the 2-0263-23A-OHD and 2-0263-23A-LD valves

• Referencing DIS 0500-04, Reactor Process Instrument Line Excess Flow Check Valve Operational Test, contains the necessary instructions to backfill RPV sensing instruments located on the 2202(3)-S and 2202(3)-6 racks.

• Model Work Orders 99159803-03 (96008863-03), IM- Backfill Sensing Lines for FT2(3)-1291-17 & FT 2(3)-1291-31 Page 2 of 3

Attachment 3 Additional RPV Make-up Injection Methods

3. Isolation Condenser (one path per unit)(Included in TSG-3 revision 12)

• Connect the hose to the drain line at the 2(3)-1301-3 valve and inject through the Isolation Condenser return line.

4. RWCU (one path per unit) 0 Hook up a hose to the drain line downstream of the 2(3)-1201-7 MOV.

5. Head Spray (one path per unit)

• Hook up a hose to the drain line downstream of the 2(3)-0205-24 MOV.

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