IR 05000369/1985038: Difference between revisions

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{{Adams
{{Adams
| number = ML20202B941
| number = ML20214G095
| issue date = 06/02/1986
| issue date = 11/13/1986
| title = Insp Repts 50-369/85-38 & 50-370/85-39 on 851015-17 & 860127-31.Violations Noted:Failure to Adequately Perform Preoperational Test on Control Room Chiller & Implement & Maintain Procedures.Related Info Encl
| title = Confirms 861208 Enforcement Conference in Region II Ofc to Discuss Findings Re Operability Concerns of Nuclear Svc Water Sys as Noted in Insp Repts 50-369/85-38 & 50-370/85-39,per 861112 Telcon.Proposed Agenda Encl
| author name = Debs B, Wilson B
| author name = Grace J
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
| author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
| addressee name =  
| addressee name = Tucker H
| addressee affiliation =  
| addressee affiliation = DUKE POWER CO.
| docket = 05000369, 05000370
| docket = 05000369, 05000370
| license number =  
| license number =  
| contact person =  
| contact person =  
| document report number = 50-369-85-38, 50-370-85-39, IEB-81-03, IEB-81-3, NUDOCS 8607100458
| document report number = NUDOCS 8611250557
| package number = ML20202B938
| document type = CORRESPONDENCE-LETTERS, NRC TO UTILITY, OUTGOING CORRESPONDENCE
| document type = INSPECTION REPORT, NRC-GENERATED, INSPECTION REPORT, UTILITY, TEXT-INSPECTION & AUDIT & I&E CIRCULARS
| page count = 3
| page count = 45
}}
}}


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November 13, 1986 Docket Nos. 50-369, 50-370 License Nos. NPF-9, NPF-17 Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:
I O  UNITED STATES
SUBJECT: CONFIRMATION OF MEETING ARRANGEMENTS - MCGUIRE NUCLEAR STATION DOCKET N05. 50-369 AND 50-370 This confirms a telephone conversation between Mr. H. Tucker of Duke Power
[WCEG 'o,$  NUCLEAR REGULATORY COMMISSION
[  REGION 11
$ ., j  101 MARIETTA STREET. * 2  ATLANTA. GEORGI A 30323
\...../
Report Nos.: 50-369/85-38 and 50-370/85-39 Licensee: Duke Power Company  -
422 South Church Street Charlotte, NC 28242 Docket Nos.: 50-369 and 50-370 License Nos.: NPF-9 and NPF-17 Facility Name: McGuire 1 and 2 Inspection Conducted: ,
Oct er 15-17, 1985 and January 27-31, 1986 Inspectors:
B. T. ' Debs
  '
      [!
Dite' Signed M
F. McCoy S. D. Stadler W. Poertner P. Moore Accompanying Personnel: Gr y on L. Yoder, Ph.D. (ORNL)
Approved by hw '. M m  b f?6 fson, Acting Section Chief  Da'te Signed B.W)ionofReactorSafety Divis SUMMARY Scope: This routine, unannounced inspection was in the area of Nuclear Service Water System Operabilit Results: Five violations were identified.
 
i i
        ,
8607100458 860727 PDR ADOCK 05000369 G  PDR
_
      . _ , ___ ._ . _
REPORT DETAILS Persons Contacted  -
Licensee Employees
+ Vaughn, General Manager, Nuclear Stations
*+T. L. McConnell, McGuire Nuclear Station Manager
*+R. L. Gill, McGuire Licensing
*+E. O. McCraw, Compliance Engineer
*+ J. Kronenwetter, Design Engineer
*+ M. Suslick, Associate Engineer Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, security force members, and office personne NRC Resident Inspectors
*+W. Orders, Senior Resident Inspector R. Pierson, Resident Inspector
* Attended exit interview on 10/17/85
+ Attended exit interview on 01/31/86 Exit Interview
      ,
The inspection scope and findings were summarized on October 17, 1985, and January 31, 1986, with those persons indicated in paragraph 1 above. The inspector described the areas inspected and discussed in detail the inspec-tion findings. No dissenting comments were received from the license The results of the inspection were discussed with utility management during a meeting in Atlanta on March 14, 1986. The details of this meeting are documented in Section 11 of this repor During the exit interview the enforcement findings were presented as preliminary and unresolved. Following NRC management review, the following findings were determined:
369/85-38-01, 370/85-39-01 Violation - Failure to adequately perform preoperational test on control room chiller - see paragraphs 7 and /85-38-02, 370/85-39-02 Violation - Failure to implement and maintain procedures - see paragraphs 7 and /85-38-03, 370/85-39-03 Violation - Failure to meet Technical Specifica-tion 3.7.4 for RN system operability - see paragraph /85-38-04, 370/85-39-04 Violation - Failure to perform 10 CFR 50.59 evaluation on degraded equipment - see paragraph r
 
369/85-38-05, 370/85-39-05 Violation - Failure to identi fy and correct conditions adverse to quality as * required by 10 CFR 50, Appendix B, Criterion XVI - see paragraph 1 /85-38-06, 370/85-39-06 Unresolved Item - NRC followup of licensee response of April 25, 1986 - see paragraph 1 . Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspectio . Unresolved Items An Unresolved Item is a matter abcut which more information is required to determine whether it is acceptable or may involve a violation or deviatio A new unresolved item identified during this inspection is discussed in Section 1 . Nuclear Service Water System Description The McGuire Final Safety Analysis Report (FSAR) states that the Nuclear Service Water (RN) System provides assured cooling water for various Auxiliary Building and Reactor Building heat exchangers during all phases of station operation Each unit has two redundant " essential headers" serving two trains of equipment necessary for safe station shutdown, and a
"non-essential header" serving equipment not required for safe shutdown. In conjunction with the Ultimate Heat Sink, comprised of Lake Norman and the Standby Nuclear Service Water Pond (SNSWP), the RN System is designed to meet design flow rates and pressure heads for normal station operation and also those flow rates and pressure heads required for safe station shutdown normally or as the result of a postulated Loss of Coolant Accident (LOCA).
 
The system is further designed to tolerate a single failure following a LOCA, and/or seismic event causing loss of Lake Norman, and/or loss of station power plus offsite power (station blackout). Sufficient margin is provided in the equipment design to accommodate anticipated corrosion and fouling without degradation of system performance,  j 6. Summary of NRC Findings i
On October 4, 1985, the NRC Senior Resident Inspector reported to Region II 1 management that the 1A nuclear service water system, designated by the j licensee as the RN system, had failed to meet the acceptance criteria of its quarterly inservice test. Although the Technical Specificttion Action Statement period of 72 hours expired on October 7,1985, both units con-tinued operation at full power based on the licensee's contention that the 1A RN pump had been made operable by cross connecting it with the Unit 2 2A RN pump. On October 10, 1985, NRC informed Duke Power Company (DPC) that operation in the unit shared mode was an unacceptable unanalyzed conditio DPC restored unit separation and began justification for continuing opera-tion with the apparently degraded pum _
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Licensee representatives stated that they suspected that the pump was not actually degraded, rather the pump discharge line flow orifice reading was in error. One of the possible reasons stated was buildup of silt, mud, or corrosion at the orific Licensee representatives subsequently stated several months later that the flow indication was erroneous and the pump was not actually degrade The NRC became concerned that if system fouling was that bad at the pump discharge, what was the status of the downstream components, especially heat exchangers. A reactive inspection was conducted October 15-17, 1985, to review these matters. Numerous phone conferences and letters were exchanged in ensuing months, and a followup inspection was conducted January 27-31, 198 l A summary of the major NRC findings presented in this report are as follows: Preop tests and subsequent surveillance tests performed in 1979 were not adequate to ascertain operability of RN component Several test procedures did not contain acceptance criteria. For example, a quarterly test of RN heat exchanger 1-A on October 7, 1985, indicated potential fouling but the test procedure contained no acceptance criteri The potential fouling was apparently pursued only because of questions from the NRC and not addressed by the licensee until October 14 when it was attributed to a faulty flow instrument. The heat exchanger was assumed to be
;  operable during this period of evaluatio *
Flow was not measured through control room air conditioner heat exchanger Test results were recorded in units of differential pressure when acceptance criteria were in units of flow rat *
Heat transfer characteristics of heat exchangers were not normally determined. Fouling factors or empirical tests could have been use *
RN system was not originally preop tested in the most limiting post-LOCA configuration in that both trains were not aligned to simultaneously draw water from the Standby Nuclear Service Water Pond.
 
l The positions of valves specified in preop test data were different from the positions in operating procedures.
 
l '
The RN system had not been flow balanced since 1982 even though engi-neering documents required it to be.
 
i a
 
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2 The following heat exchanger fouling problems had occurred:
Containment spray heat exchanger 1A tested per IEB 81-03 showed
;    increasing delta P from 20 psid- in 1983 to 29 psid in 198 In October 1982, a containment ventilation heat exchanger would not function due to foulin Periodic cleaning of control room air conditioning heat exchangers had been necessary since 1982 due to foulin RCP motor coolers required cleaning three times during the period 1984 - 198 Unit 1 component cooling water heat exchanger observed to be fouled in September 198 ; Inservice testing of the 1A RN pump indicated degraded flow on i    October 4, 1985. Instead of entering a Technical Specification Action Statement which would have required the operating unit to be brought I to the hot standby mode within six hours, the licensee inappropriately cross-connected RN train A and train B and continued to operat A flow balance test on RN train IA conducted on December 17, 1985, revealed flow rates through several safety-related heat exchangers to be below FSAR values. At the request of the NRC in January 1986, the licensee evaluated these test results pursuant to 10 CFR 50.5 This evaluation, which was based upon heat transfer tests by DPC and calculations by Westinghouse, was completed and justified continued operation on January 14, 1986. .The licensee apparently assumed the system to be operable between December 17 and January 14.
 
'
I    Although it appears that RN heat exchangers were becoming progressively more fouled with time, the licensee did not recognize the symptoms or place priority consideration on the overall system operability and associated safety concerns. Rather fouled components required for continued operation were cleaned as needed but no regard shown for the status of dormant safety equipment, such as the containment spray heat exchanger When the concern was raised by the NRC, the licensee devoted significant resources toward correcting the problem. As a result, during the months of investigation, there were several instances when individual components
!    were found not to be capable of FSAR specified performance. On these occasions, the licensee revised their accident analysis supporting calcula-tions to justify continued power operation. This mode of operation complies with regulatory requirements but does not appear to represent to the NRC the most conservative safety philosoph ,
 
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7. McGuire Nuclear Service Water System History 1979 Preoperational functional testing was completed by the licensee on July 25, 1979, for the Unit 1 RN system and on November 12, 1982, for the Unit 2 RN
; system. In January 1986, NRC Region II inspectors reviewed selected areas
,
of preoperational test packages for both Units 1 and 2 RN systems.
:
l It was noted that during the conduct of the Unit 1 preoperational tests j of nuclear service water, the safety evaluation section (8) of the major 1 procedure form was marked as not applicable. Administrative Plant Manual,
; Section 4.2.4.1(e) requires that prior to procedure use, a safety evaluation
; of major changes to a procedure shall be performed. Examples of the major changes made to the preoperational procedures included changes to the minimum acceptable RN flow criteria, initial RN system configuration at
>
test initiation, and the methods utilized to determine component flow The use of "not applicable" for safety evaluations was allowed by a licensee internal memorandum dated September 14, 197 The memorandum deleted the procedural requirement for a safety evaluation prior to fuel load.
 
,
The primary objective of the nuclear service water preoperational functional test was to verify that the system could supply designed cooling water flow j to variou., components and to set each component throttle valve to provide the proper flow rate. Adequate system and component flow was to be verified j for all modes of operation.
 
i i One of the safety related RN loads during post-LOCA conditions is the l control room air conditioner which requires a minimum flow of 789 GPM as j stated in McGuire FSAR Table 9.2.2-1(8). During the RN preoperational
,
test for Unit 1, the flow to the control room air conditioning was unable I
to be determined due to problems encountered with the installed instrumen-l tation. Subsequently, a major change to the preoperational test procedure,
! TP/1/A/1400/01, was approved by the licensee to delete the requirement to verify the minimum RN flow of 789 GP The change to the preoperational test was justified by the licensee on the basis that the flow control valve is air operated and fails open during accident conditions. This justifi-cation assumed that there were no internal obstructions and that the wide open valve flow would meet or exceed the FSAR~ required flow. Due to this procedure revision, the subsequent RN preoperational test for Unit 2 also did not verify adequate flow to the control room air conditionin As stated later in this report, subsequent functional flow test data
; obtained in late 1985 and early 1986 indicated that the required 789 GPM
, was not being met. Failure to test the aforementioned component represents
 
a violation of 10 CFR 50, Appendix B, Criteria XI which requires a test program to be established to assure that all testing required to demon-a strate system components perform satisfactorily in service (369/85-38-01, 370/85-39-01).
 
'_
 
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The inspector noted that in several instances during the conduct of the preoperational tests of the RN system, the measured flows were stated as differential pressure (psid) rather than flow (GPM). The engineers who performed the tests and the preoperational logs indicated this was due to [
problems experienced with the instaihd flow instrumentation. To continue  !
the tests with the inoperable flow instrumentation, the licensee utilized i temporary differential pressure instrumentatio The conversion from j differential pressure to GPM was not made on test data enclosures. To verify that the minimum FSAR flow results were achieved for the RN compo-nents preoperationally tested, the inspector, in early 1986, requested that ;
the licensee convert the differential pressures to flows. In each case it I was verified, based on the licensee's calculations, that the minimum accept- #
able flow rates had been achieved as stated in McGuire FSAR table 9.2.2- The values from that table appear later in this repor ,
To assure minimum RN component flows, including adequate flow to the con- I tainment spray heat exchangers during design LOCA conditions, the normally :
      '
throttled valves associated with each RN component were required to be set during p'reoperational testing of the RN syste These throttled positions ,
established during preoperational testing were to be incorporated into  l operating and surveillance procedures to protect these throttled settings !
      '
during future operations. The inspectors noted that, in some cases and particularly for Unit 1, the throttled valve positions listed in the  ;
      '
licensee's RN operating procedures and their locked valve verification procedures were not consistent with earlier preoperational "as left" dat It was noted, however, for those throttled valves reviewed, the operational positions were further open than the "as left" preoperational test posi-tion The licensee acknowledged these discrepancies and committed to revise the operational procedures to meet those valve settings established ;
during recent 1985 and 1986 RN flow testin The inspection team noted that since 1976 the licensee has had a functional r system description for the RN system. Section 5 of this system description :
(MCSD-0138.00) states that annually each essential RN train must be checked !
for proper throttling. Also, after any throttle valve is repositioned, the entire train must be checked for proper throttling. The system descriptio A then presents a detailed procedure to verify that the minimum flow condi-tions for operability of the safety related portion of the system are me ,
 
The licensee had decided not to adopt the aforementioned recommendation l Consequently, no RN flow balances had been performed - beyond 1982 until
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requested by the NRC in late 198 Functional system descriptions are
 
not used as procedures by licensees and, consequently, failure to follow
'
MCSD-0138.00 is not considered to be a violatio However, compliance with this document would have prevented the above violatio However, The requirements to verify proper throttling position should have been in plant procedure ;
Failure to measure flow through components and failure to specify post-tions of throttled valves in procedures represent examples of inadequate
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procedural controls and are, therefore, a violation of McGuire Technical Specification 6.8.1 and 10 CFR 50, Appendix B, Criteria V which requires that adequate written procedures be implemented and maintained (369/85-38-02,370/85-39-02).
 
In addition to adding procedural requirements for RN throttled valve posi-tions as addressed above, the licensee has implemented several other posi-tive methods to control these valves. Currently, these valves are verified locked every six months under the Locked Valve Verification Procedure 4700/23. In addition, independent verification is utilized to ensure that the valves are returned to the proper position following valve repositioning for maintenance or other activitie Despite these positive controls, the inspectors noted the following recent deficiencies in the licensee's control over these throttle valves:
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The Locked Valve Verification Procedure requires that the operator verify the valve to be locked. No verification of the actual throttle position is required.
 
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The valve locks utilized for RN throttled valves are chain lock These chain locks work well for wide open valves, but the slack in the chains cannot ensure that a valve remains open 1/4 turn. A valve that is required to be open 1/4 to 3/8 turn could be locked in the full-closed position without detection.
 
One potential solution identified by the licensee for better control of these throttle valves include the use of locking collars which are used on throttle valves in other system Since the locking collars can be sized to ensure the exact valve opening desired, their use would provide positive indication of valve position.
 
The licensee initiated a 10 CFR 50.72 notification to the NRC stating that prior to January 27, 1986, the RN systems for Unit 1 and 2 had never been tested under the requisite design basis accident configuratio Specifi-cally, the system valves had never been positioned to supply the required flow to essential headers for Units 1 and 2 with the system taking suction solely from the Nuclear Service Water Pon This issue is discussed in Section 6. of this repor In response to IE Bulletin 81-03 which addressed the potential fouling of safety related heat exchangers by clam and shell debris, the licensee com-mitted to the NRC to monitor two RN supplied heat exchangers on a quarterly basis. One of these heat exchangers is the 1A Containment Spray (NS) heat exchange Additionally in the licensee's response, it was stated that
"if significant fouling is detected on these heat exchangers, other heat exchangers in the RN system will be inspected." The licensee performed their monitoring under procedure PT/1/A/4403/04. This procedure for the 1A NS heat exchanger requires that the test be performed for a FSAR accident
 
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4 i
RN flow of 5000 GPM to the NS heat exchanger and that the heat exchanger
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differential pressure (D/P) be recorde In October 1985, the inspectors reviewed the past test data which indicated the following:
DATE OF TEST  D/P (PSID)
l 6/20/83  20
! 9/22/83  Not Available 10/2/83  2 ! 1/18/84  25 4/11/84  23 7/18/84  25 29.5
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11/9/84 2/28/85  2 /27/85  25
*10/7/85  29
*RN flow was 4600 GPM The test procedure did not specify criteria for determining "significant fouling" and, tnus, other components were not inspected as a result of
'
these test Further discussion of these findings appears later in this report under the section titled 198 l 1982 On October 22, 1982, the licensee identified that fouling of the RN supplied  ,
lower containment ventilation heat exchangers was a problem which was causing unacceptable temperature increases in the lower containment area This subsequently forced the units to operate at reduced reactor power during certain seasonal condition In April 1983, the licensee attempted to add a penetrant / dispersant to the RN system in an attempt to clean lower
: containment cooling unit The attempt was ineffectual. Eventually the  ,
licensee modified the coolers with a self-cleaning mechanism which corrected the proble As a result of a control room air conditioning trip due to fouling of the RN supplied, safety related air conditioning chillers, the licensee established a cleaning threshold based on increasing air conditioning condenser pres-  i sures. On the following dates, these chillers have been rodded out to maintain operabilit TRAIN A  TRAIN B 11/19/82  3/83
! 10/03/83  01/07/85 12/19/83  10/21/85 05/30/84  11/05/85    i 10/31/84      l 09/25/85      l 10/24/85      i 10/31/85
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1984 In March 1984, the licensee began development of a heat exchanger perform-ance monitoring program. At the time of this inspection, Duke Power Company had not fully implemented this program at their nuclear plan The inspector reviewed the section of the program which requires monitoring the performance of heat exchangers such as those in the RN system. The program appeared to be very comprehensive with provisions for monitoring both flows and heat transfer capabilities, for increasing the frequency of monitoring as warranted, and for initiating corrective actions as necessar Once fully implemented, this Performance Monitoring Program will be a major improvement in the licensee's ability to monitor plant equipment perfor-mance and to promptly identify degraded performance. A key to the relative
+ success of the program, however, will be the effectiveness and timeliness of corrective actions taken in response to an identified deficienc The inspector noted that this corporate monitoring program was scheduled to be implemented in stages at the various plants. The RN heat exchangers were scheduled for performance monitoring implementation during the second phase of the program which will be several months into 198 As a result of the fouling and degraded performance being experienced with the RN heat exchangers and concerns expressed by the NRC, the licensee indicated this phase of the program will be implemented on a priority basi Also in 1984, the licensee began to experience RN fouling problems in their reactor coolant pump motor coolers. The licensee has performed the following cleanings of these coolers on the dates indicated:
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UNIT 1  UNIT 2 12/31/84  8/10/84 11/08/85 In September 1984, the licensee evaluated the Unit 1 Component Cooling (KC)
heat exchanger for fouling, although, according to the licensee, there was no indication of reduced heat transfer or high differential pressure. As part of the evaluation, DPC engineering calculated a fouling factor for the KC heat exchangers. These calculations were based on informal test data which appeared to the cognizant engineer as nonrepresentative. In November 1984 the Unit 1 KC heat exchanger was cleaned. In June and July 1985, the
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Unit 2 KC heat exchanger was cleaned. Although visual inspection of the heat exchanger by DPC engineering did not support the calculated fouling factor (the calculated fouling factor appeared to be less conservative),
the licensee did not perform further evaluation of past operability of these heat exchangers.
 
t
 
1985 On October 4, 1985, following in-service testing, the 1A Nuclear Service Water pump performance was found to be degraded. The pump curve generated from the test data deviated from the previously established base-line curve. Delivered flow was estimated to be approximately 85 percent of that required. Technical Specification (TS) 3.7.4 requires two loops of RN to be operable. With only one loop operable, they must restore both loops to operable within 72 hours or be in hot standby within the next 6 hours and cold shutdown within the following 30 hour The licensee performed a 10 CFR 50.59 analysis to justify cross connecting the 1A and the 2A RN trains in an attempt to boost IA RN flo After reviewing the 50.59 analysis and extensive interaction with the licensee, the NRC Region II, on October 10, 1985, informed the licensee that the NRC considered the licensee was not meeting the requirement of TS 3.7.4 which requires two operable RN loops since the 1A train was inoperable due to a degraded pump and that the cross connected configuration could not be justified by a 50.59 analysis since it represented the possibility of an unreviewed safety question and, in effect, changed the Technical Specifica-tio The licensee's action to cross connect the 1A and 2A RN trains and to con-tinue two unit operation for greater than 72 hours was contrary to TS 3. and, therefore, represents a violation (369/85-38-03, 370/85-39-03).
 
During this time period, the licensee discovered that one of the cross connect valves had an erroneous position indicatio Thus, the valve was actually closed when thought to be ope This matter was discussed previously in Region II Inspection Report 50-369/85-35, 50-370/85-3 As a result of the interactions with the NRC, the licensee split the RN trains and took compensatory measures to continue operation of the 1A train under reduced flow condition Further details of the apparent degradation of the 1A RN pump are contained in NRC Region II Inspection Report 50-369/85-37. As a result of the aforementioned event, during the
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period of October 15-17, 1985, Region II inspectors reviewed the overall RN system performance in light of the recent even The inspectors reviewed the licensee's quarterly performance, PT/1/A/
4403/04, data on the 1A NS heat exchanger which was tabulated earlier in this report under 198 The following observations were made by the inspectors regarding PT/1/A/
4403/04:
The performance test lacked qualitative and quantitative acceptance criteri * The test results suggest an increasing D/P across the 1A NS heat l exchange ;
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The pressure drop could not be measured at the required design basis accident RN flow of 5000 GPM for the 1A NS heat exchanger because this flow could not be achieved for the test performed on October 7,198 The measured flow was recorded as 4600 gpm.
 
* The 1A NS heat exchanger outlet throttle valve was closed to the extent that the as found flow through this heat exhanger was 800 gp It appears doubtful that the required accident flow of 5000 gpm could have been achieved with this as found valve position.
 
The licensee indicated that, at that time, a qualitative or quantitative acceptance criteria had not been determined but that work had begun to provide such criteri CFR 50 Appendix B Criteria V states that procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to this regulation, PT/1/A/4403/04 did not contain an appropriate acceptance criteri This represents another example of violation (319/85-38-02, 50-370/85-39-02).
 
Regarding the aforementioned increasing D/P across the 1A NS heat exchanger, the licensee indicated that, although the test results suggest an increasing D/P, some mathematical analysis should be performed to prove the apparent trend of an increasing D/P.
 
Regarding the low 1A NS heat exchanger RN flow recorded on October 7, 1985, the licensee indicated that the low reading could have been a result of a calibration proble As a result of the inspector's questioning, the licensee issued Work Request Number 65574 to check the calibration of the flow instrument used to obtain the recorded 4600 GPM. On October 14, 1986, the calibration results indicated that, at a flow of 5000 GPM, the instru-ment indicated 4820 GPM. The licensee then took action to recalibrate the instrument.
 
Based on the data reviewed and discussions with licensee personnel, the inspector stated the following concerns:
Since the licensee did not have an acceptance criteria for the in-creased D/P, could the apparently increasing D/P suggest heat exchanger fouling which may have reduced heat exchange capacity to an unaccept-able level? Could system flow reductions due to fouling affect other RN system component performance? These concerns were discussed with plant management on October 17, 1985. The inspector requested manage-ment to consider the feasibility of performing a RN system integrated flow test to provide confidence that all RN safety related loads could be provided the requisite design basis flows. Additionally, the inspector discussed the feasibility of measuring the heat transfer capability of the 1A NS heat exchange _
 
      - _ _ _ .
 
After growing concern by NRC Region II regarding the current ability of the Unit 1 RN system to perform its safety function under accident condi-tions, the licensee was requested, on October 18, 1985, to provide the NRC Region II Office with a statement of operability for the RN syste On October 23, 1985, the operability statement was received from tne license This :tatement concluded that the RN system is operable and capable of performing its intended safety functio The statement of operability included an engineering evaluation by Duke Power Company. The evaluation summarized the results of a Westinghouse computer calculation which utilizes the LOTIC code. This code predicts containment pressure response from inputs including the heat transfer capability (UA) of the containment spray and component cooling water heat exchangers. The Duke Power engineering calculations used to determine the UA for the 1A NS heat exchanger assumed the same fouling factor which was calculated for the Component Cooling Water (KC) heat exchanger in early 198 The inspectors expressed reservation over this assumption; questioning the credibility of applying the existing fouling factor for a single pass horizontal type heat exchanger (KC heat exchanger) to the NS heat exchanger which is a vertical U-tube heat exchanger. Additionally, RN flows through the tubes of the KC heat exchanger unlike the NS heat exchanger where RN flow is on the shell sid It, however, was agreed by the NRC that for lack of any other available data this approach was accept-able until specific empirical data could be obtaine Based on the aforementioned assumptions and calculation as utilized in the LOTIC program (WCAP-8282), a maximum containment pressure of 13.3 psig was predicted during a design basis acciden The McGuire containment design pressure is 15.0 psi In response to NRC concerns over the potential fouling and degradation of the 1A NS heat exchanger, the licensee developed a performance test PT/0/A/4208/01, Containment Spray Heat Exchanger Performance Test. The purpose of the test was to:
Determine if a high flow flush reduces the heat exchanger differential pressur Assure the structural integrity of the heat exchanger tube Determine the overall heat transfer coefficient and fouling factor of the NS heat exchanger The McGuire FSAR analysis utilized a containment spray heat exchanger UA of 2.J4 x 10' BTU-Hr-Deg. F. Empirical data from the aforementioned test indicated that an actual UA of 7.35 x 105 BTU-Hr-Deg. F existed under
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current plant conditions. This information was provided to Westinghouse on November 27, 1985, to perform a LOTIC run utilizing this data. A con-tainment response model which is less conservative than the one used in the FSAR analysis was used by Westinghouse (WCAP-10325) for this run. Use
  , _ .  - ,
 
of this model was accepted by the NRC since this WCAP had been reviewed and found technically sound by the NRC staff, although the NRC's Safety Evaluation Report had not been issued at that tim This LOTIC run of November 27, 1985, indicated that, for the aforementioned UA, a peak containment pressure of 14.42 psig would be realized under design basis accident condition In addition to the heat transfer test, the licensee performed a heat exchanger tube integrity test using the tritium activity of the Refueling Water Storage tank (RWST) as a tracer sourc The test results indicated insignificant leakag Several cleaning attempts using various chemical and hydraulic techniques were employed by the licensee to clean the 1A NS heat exchanger. The latest performance test results (January 28, 1986) indicate that a UA of 2.03 x 10' BTV/Hr-Deg. F had been achieve The inspectors viewed video tapes of the licensee's fiber optic inspection of the 1A NS heat exchanger. Approximately the first seven feet of the upper portion of -the tube bundle could be viewed. The tape indicated that a fairly uniform silica deposit completely covered the tubes, prior to cleanin Confirmatory UA calculations were performed by the inspection team. These calculations appear as Attachment 4 to this report. Those calculations closely approximate those of the licensee.
 
'
8. Review Of Flow Balance Testing The inspectors conducted a review of the RN flow balance testing conducted on December 17, 1985, January 27, 1986, and January 28, 1986, for Train IA of the Nuclear Service Water System. Additionally, flow balance testing conducted on January 30, 1986, for Train 1B of the Nuclear Service Water System was reviewe The Train 1A flow balance test conducted on December 17, 1985, was in accordance with procedure TT/1/A/9100/105, Change 0 through Change The test provided for:
-
Isolation of Train IA and 1B essential heade The low level intake providing Train 1A suctio Isolation of the Unit I non-essential header from Train 1 Control Room and Equipment Room A Train Cooling Chillers being supplied by Nuclear Service Water Train 1A.
 
      ,
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-
Securing of Nuclear Service Water Train 2A due to a condition of Nuclear Service Water operability resultant from prior degraded pump performance in Train IA when supplying Control and Equipment room coolin Alignment of service water valves in accordance with a lineup that was consistent with actual Safety Injection and Containment Spray condition The Train 1A flow balance test conducted on January 27, 1986, was per-formed in this same manner with the exception that Change 2 of _ procedure TT/1/A/9100/105 was also in effect which changed the Train IA suction from the low level intake to the service water pond in order to duplicate the most restrictive condition of operation for testin Flow rates through those essential heat exchangers required to mitigate accident consequences during Safety Injection and Containment Spray were measured during these tests and compared to target values which were specified in the FSAR. Measurement results and comparisons for Train 1A tests are delineated in Table 1.
: The data for the December 17, 1985 test reflects that FSAR specified flow rate values could not be attained for the containment spray heat exchanger (4% degraded), control room chiller heat exchanger (10*s degraded), the charging pump oil cooler (46% degraded), spent fuel pool pump room ai*
handling unit (27% degraded), and containment spray pump room air handlirg unit (56% degraded).
 
Although the data from the December 17th test indicated multicomponent degradation, the licensee performed an informal evaluation to support continued operation. The results of this evaluation were not documente Not until requested by the NRC in January 1986, did the licensee perform a detailed engineering evaluation as required by 10 CFR 50.59. Failure to perform this requisite evaluation is considered a violation of the aforementioned 10 CFR 50.59 (369/85-38-04, 370/85-39-04).
 
In an operability statement dated January 14, 1986, the licensee performed an engineering evaluation to demonstrate the adequacy of the tested perform-ance of the charging pump oil cooler, the containment spray pump room air handling unit and the spent fuel pool cooling pump room air handling unit with the observed reduced flow rates. In the operability statement the licensee stated that the degraded containment spray heat exchanger flow was adequate, and justified continued operation of Unit This operability statement was based on the actual tested values of the thermal efficiency for this particular heat exchanger and a containment pressure calculation performed by Westinghouse and forwarded to Duke Power Company by letter DAP-86-513 dated January 16, 1986. The Westinghouse calculation was based on assumptions which included the following:
*
An active sump volume of 90,000 cubic fee A thermal efficiency heat transfer coefficient of VA=7.35 x 105 BTU-Hr-Deg. F for the containment spray heat exchanger and UA=1.64 x 10' BTU-HT-Hr-Deg. F for the RHR heat exchanger. The licensee stated that, for the containment spray heat exchanger, this represented a 75%
reduction in the UA coefficient. This value was a conservative selec-tion by the licensee since the testing performed on December 17, 1985, demonstrated the UA value to be nearly 58% degrade Under these assumptions the Westinghouse calculation demonstrated that during a LOCA, containment pressure would remain below the containment design pressure of 15 psig with service water flow through the containment spray heat exchanger reduced to 4800 gp The licensee, therefore, con-sidered that the results of their evaluations and calculations justified continued operation of Unit The basis for this conclusion was reviewed and accepted by the NRC Between December 17, 1985 and January 27, 1986, three cleaning cycles were accomplished on the RN side of the 1A containment spray heat exchanger. The licensee concluded that heat exchanger thermal ef ficiency increased from 42.1% to 74.7% as a result of these cleaning cycles. The affects of these cleaning cycles is also demonstrated in the reduced RN header pressure delineated in Table 1, for the flow balance test of January 27, 198 The data in Table 1 for the January 27, 1986 test reflects that, even af ter the cleaning evolutions, FSAR specified flow rate values could again not be attainec for the containment spray heat exchanger (2% degraded), control room chiller heat exchanger (0.5% degraded), Spent Fuel Pool Pump Room Air Handling Unit (30% degraded), containment spray pump room air handling unit (56% degraded), diesel generator cooling water heat exchanger (8%
degraded), and safety injection pump motor air handling unit (15% degraded).
 
Degradation of the charging pump cooling flcws was attributed to faulty flow indication which required instrument replacemen The licensee stated that as a result of this test,' Train 1A of nuclear service water v's declared inoperable pending resolution of the degraded flow conditions and correction of the faulty flow indicator associated with the charging pump oil coole The inspectors noted that these flow balance tests were accomplished with Unit 2 Train A secured which was not conservative with respect to the design basis accident. Worst case conditions should assume Unit 2 Train A providing unit coaldown loads during the operation of Unit 1 Train A to mitigate accident conditions. This in effect would reduce the net positive suction head for Unit 1 Train A. The inspectors considered that testing should reflect this conditio The licensee stated that on January 28,
,
1986, another flow balarce would be performed and that Train 2A would service necessary cooldown loads for Unit 2 during this test.
 
!
 
P
 
In conjunction with resolution of the degraded flow conditions reflected in the service water Train 1A flow balance testing, the licensee had requested that Westinghouse perform an analysis to determine new acceptable minimum values of service water flow through containment spray and component cooling water heat exchangers. The licensee was considering that a throttling back of these two major heat exchangers would result in a higher RN header pressure thus providing increased flow thru the smaller essential heat exchangers. A Westinghouse calculation was forwarded to Duke Power Company in January 1986 which demonstrated that, with service water flow through the component cooling water heat exchanger reduced to 6000 gpm and service water flow through the containment spray heat exchanger reduced to 3800 gpm, peak containment pressure would remain below the containment design value of 15 psig during a LOCA.
 
On January 28, 1986, a third nuclear service water flow balance test was accomplished on train IA. This test provided for reduced target flow values of 6000 GPM through the component cooling water heat exchanger and 3800 gpm through the containment spray heat exchanger which the licensae considered to be acceptable target values based on the aforementioned Westinghouse calculation. This flow balance test was performed under the same conditions as the January 27, 1986 test with the exception that Train 2A was aligned to provide a cooldown load of greater than or equal to 6000 gpm for Unit 2, the flow instrument for the charging pump oil cooler had been replaced, and the RN system took suction only from the SNSWP. The results of this test are delineated in Table 2. The result of this test demonstrated that flow values through all heat exchangers were within the new acceptable values established by the licensee within the operability statement of January 14, 1986. On March 11, 1986, the licensee made a 10 CFR 50.72 notification to the NRC stating that, prior to January 27, 1986, the RN system for both units had never been tested under the requisite accident conditions with all RN being supplied by the SNSWP. Apparently after addressing both NRC and DPC engineering concerns regarding the desired RN flow test system configuration, the licensee later realized that the preoperational test configuration had not tested the system under the design basis accident configuratio The aforementioned event represents another example of a violation of 10 CFR 50, Appendix B, Criterion XI (369/85-38-01, 370/85-39-01).
 
The NRC later learned from the licensee that during the establishment of the flow test system configuration on January 28, 1986, the RN system entered a pressure transient. While base loading the RN pumps (gradually placing requisite heat exchangers on the line), a significant decrease in RN header pressure was experienced. This event was not allowed to go full term and was terminated by throttling down on large component flows. The test was repeated with the throttled valve positions and acceptable results were obtained. On March 12, 1986, NRC Region II learned of the January 28 flow transient shortly after DPC management had been informed of i The NRC expressed concern regarding the transient since it suggests that, under actual accident conditions, the RN system's pumps could have lost net positive suction head resulting in a loss of the ultimate heat sink for both units. This concern is further addressed in Section 10 of this repor ~
 
  . . _
;
 
The Nuclear Service Water Train IB flow balance test was conducted on
, January 30, 1986, with the same test methodology utilized for the January 28, 1986 flow balance test for Train 1A. The results of this test are delineated in Table 3. The results of this test demonstrated that
; established operability values could not be obtained for the Spent Fuel Pool Pump Room Air Handling Unit (5% degraded) and the Residual Heat Removal Pump
, Room Air Handling Unit (1% degraded). The licensee was advised by the NRC that prior to establishing Train IB as being fully operable, these degraded
 
conditions would require further evaluation and resolution.
 
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TABLE 1 Results of Heat Exchanger Flows and Comparison to FSAR Target Values During Nuclear Service Water Train 1A Flow Balance Testing of December 17, 1985 and Janua ry 27, 198 December 17, 1985 Data    Janua ry 27, 1986 Ta rget Flow  flow Rate Header  Flow Rate  Header Pressure Heat Exchanger  Rate (CPM)  (CPM) Pressure (psig)  (CPM) (psig) Component Cooling Water  8000  0000 6 ' Conta inment Spray  5000  4800 6 l Diesel Generator Cooling  900  900 6 ; Water              i Control Room Chiller  789  707 6 . Cha rg i ng Pump Oi l Coo l e r  28  15 6 i Safety injection Pump  20  21 6 Oil Cooler c
' Spent fuel Pool Pump  20  1 .5    14  56 *
Air Handling Unit Conta inment Spray Pump  45  20 6 Air Handling Unit Residual Heat Removal  45  51 6 Pump Air Handling Unit            ,
i
:
$
 
1
        -_ - _ -
    - ,, - , - -. ,  , -  . - -  .,
 
~ - .. - -- - . - - - . . . . ~ . . . - . . . . - . ~ . . . ~ - . - . . _ . - . . - . . _ . . - - - - - . - - _ _ . - - _ - - - -  . - - - -
              *
l TABLE 2 Results of Heat Exchanger Flows and Comparison to FSAR Target Values and Licensee Established Operability Values During Nuclear Service Water Train 1A Flow Balance Testing of January 28, 198 January 28, 1986 DATA Licensee Established Target flow  Ope ra b i l i ty Va l ue  Flow Rate  Header Pressure Heat Exchanger  From FSAR (CPM)  ' for Flow (GPM)  (GPM)  (psig)
              ,
1 Component Cooling Water 8000  6000+  6000    6 ; Containment Spray  5000  3800+  3970    6 . Diesel Generator Cooling 900  900  950    6 Water Control Room Chiller  789  789  946    6 . Cha rg i ng Pump Oi l Coo le r . 28  15  22    6 . Safety injection Pump  20  20  23    6 Oil Cooler          , Spent fuel Pool Pump  20  1 .5 Air Handling Unit Conta inment Spray Pump  45  2 .5    6 Air Handling Unit Residual Heat Remova l  45  4 .5    6 Pump Air Handling Unit
+ Based on assumption that Containment Spray Heat Exchanger Thermal Efficiency is greater than or equal to 70%.
The rma l performance data reflects it is currently 74.7% and past history indicates degradation will inc rea se due to foulin . - _ . - , - .-  _ .. ._,____,_ _._ _._ . ,,_ ,_
 
- - - _ _ _ - - . - _ _ . _ - . . - - . . _ - . _ _ - . .. . - - _ . _ - _ . - - . - - - ~ . - _
        . _
          . - . . _ . - _ . . . . . -- -..
I TABLE 3 Results of Heat Exchangor Flows and Comparison to FSAR Target Values and Licensee Established Operability Values During Nuclear Service Water Train IB Flow Balance Testing of January 30, 198 January 28, 1986 DATA I      Licensee Established j  -
Ta rge t flow Ope ra b i l i ty Va l ue  Flow Rate Header Pressure Heat Exchanger  From FSAR (GPM) for Flow (GPM)  (GPM)  (psig)
j I
1 Component Cooling Water  8000 6000+  6900  52 Conta inment Spray  5000 3800+  5000  52 Diesel Generator Cooling  900  900  920  52 Water j Control Room Chiller *
789  789  912  52 i Cha rg ing Pump Oi l Coo le r  28  15  20  52
, Safety injection Pump  20  20  2 Oil Cooler Spent ruel Pool Pump  20 1 Air Handling Unit f
, Containment Spray Pump  45 2 '
Air Handling Unit Residual Heat Removal  45 4 .5  52 Pump Ai r Handling Unit
  + Based on assumption that Containment Spray Heat Exchanger Thermal Erriciency is greater than or equal to 70%.
Thermal performance data reflects it is currently 74.7% and past history indicates dearadation will inc rea se due to rouling.
 
I l
      ,    . - - .
 
Following performance of the nuclear service water train IA flow balance test of January 28, 1986, the inspector observed a train IA Diesel Generator operability tes During performance of this test, the inspectors noted that the flow indicator for service water flow through the diesel generator cooling water heat exchanger was off scale high (greater than 1000 gallons per minute) rather than indicating an expected value of 900 gallons per minut Interviews with licensee personnel who had performed the earlier Train 1A flow balance test reflected that, during test restoration, valve IRN73A was left in the test position rather than being returned to the normal positio The test position for this valve is " throttled to 900 gallons per minute in the test lineup configuration". The normal position for this valve is " throttled to 900 gallons per minute in the normal lineup configuration." Since the normal RN system lineup configuration isolates the large engineered safety feature loads, RN header pressure was increased which resulted in greater flow through those valves which were not throttled back from the test position. Failure to restore valve IRN73A to its normal position is contrary to step 12.8 of procedure TT/1/A/9100/105 and is a third example of a violation for failure to properly implement procedures (369/85-38-02,370/85-39-02).
 
The inspectors noted that restoration of the 1A train service water diesel generator heat exchanger outlet isolation valve (IRN73A) and the 1A train service water containment spray heat exchanger outlet isolation valve (IRN137A) to their normal throttled positions could result in insufficient nuclear service water flow being supplied to the diesel generator heat exchanger and containment spray heat exchanger when the containment spray heat exchanger is placed on line during transfer to cold leg recirculation unless specific operator actions were taken to ensure proper flow through these heat exchangers. A review of the emergency operating procedures for safety injection (EP/1/A/5000/01, EP/2/A/5000/01) and for transfer to cold leg recirculation (EP/1/A/5000/2.3, EP/2/A/5000/2.3) reflected that provi-sions were not established to assure proper service flow through the diesel generator cooling water heat exchanger and containment spray heat exchanger when these component were required during accident condition These inadequacies in the emergency operating procedures are considered a fourth example of violation 369/85-38-02, 370/85-39-02, failure to properly establish and implement procedure During the course of this inspection, test procedure TT/1/A/9100/105, RN Train 1A Flow Verification, was revised, and test procedure TT/1/A/9100/107, RN Train IB Flow Verification, was written to leave the service water outlet isolation valve to the containment spray heat exchangers in the tested throttle positio Additionally, licensee actions were initiated to revise emergency operating procedures EP/1/A/5000/01, EP/2/A/5000/01, EP/1/A/5000/2.3, EP/2/A/5000/2.3 in order to establish adequate service water flow through the diesel generator heat exchanger and containment spray heat exchanger, during safety injection and transfer to cold leg recirculatio . _ _
!
. 19 9. Changes to the McGuire Containment Pressure Response Model During the course of the licensee's engineering evaluations to justify the apparent RN system degradation, many changes were made to the input parameters used in the McGuire containment pressure response mode The following parameters have significant effect on peak containment pressure:
ice mass
*
NS and KC heat exchanger UAs
*
NS and KC heat exchanger tube and shell flows
*
mass and energy releases into containment
* auxiliary containment spray flow
*
auxiliary containment spray actuation time
*
active containment sump volume Table 4 provides a chronology of these parameters and when each parameter was changed by Duke. Some values such as active containment sump are based on engineering judgement by Duke since calculations have not been completed to justify the valu TABLE 4 McGuire Containment Pressure Response Model Changes Parameter  10/31 11/28 1/17 1/28 Ice Mass  2.220 2.220 2.220 2.220 (millions of LBM)
NS HX UA  1.86 0.735 0.735 2.03 (millions of BTU /HR- F)
KC HX UA  5.00 5.00 5.00 2.98 (millions of BTU /HR- F)
NS/RN Flow (GPM)  5000 5000 4800 3800 KC/RN Flow (GPM)  8000 8000 8000 6000 Mass and Energy Release 1974 1979 1979 1979 Model (year)
ND Containment Spray 1623 1623 1841 1841 '
      ,
Flow (GPM)
NO Containment Spray 3000 3000 3000 3000 Actuation Time (SEC)
l
 
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
 
Active Containment 46,500 46,500 90,000 90,000 Sump Volume (FT3)
Peak Pressure (Psig) 1 .42 14.45 12.7 10. RN System Walkdown The inspectors conducted a detailed walkdown of portions of the Unit 1 Nuclear Service Water System. The inspectors reviewed the system operating procedures, the valve checklist procedure and the system piping drawing The inspection was conducted to confirm that procedural valve lineups and drawings matched the as-built configurations, to verify that equipment conditions were satisfactory and items that might degrade performance were identified and evaluated, to verify that valves were in proper positions and locked if appropriate, and to verify that instrumentation was properly valved i The inspectors made the following observations. Valves 1RN 893 and 1RN 894, the inlets to the 1A1 and 1A2 Diesel generator Air Dryer and af ter dryer respectively, were mislabele Valve 1RN894 was labeled as IRN893. The Nuclear Service Water System valve checklist correctly described these valves and the licensee made arrangements to correct the label plates on the valves prior to the inspector leaving the sit The inspector noted slight inaccuracies in the system piping diagrams, in that relief valve 1RN-295 is located upstream of flow element 5360 as opposed to downstream as indicated on DWG MC-1574-2.0 and vent valve IRN141 is located upstream of flow element 5930 as opposed to downstream of the flow element as indicated on DWG MC-1574- The licensee made arrangements to correct these inaccuracies prior to the inspectors leaving the site.
 
11. Details of NRC/DPC Management Meeting Held on March 14, 1986 Attendance at the Duke - NRC Management Conference on March 14, 1986, held at DPC's request at the NRC's Region II Office included:
Duke power Company G. Vaughn, General Manager, Nuclear Stations T. L. McConnell, McGuire Nuclear Station Manager    ,
W. A. Haller, Manager, Technical Services    '
R. L. Gill, McGuire Licensing    ,
B. H. Hamilton, McGuire Superintendent of Technical Services  l J. E. Snyder, Supervising Engineer    !
E. O. McCraw, Compliance Engineer W. J. Kronenwetter, Design Engineer R. W. Revels, Design Engineer W. M. Suslick, Associate Engineer
 
,
Nuclear Regulatory Commission R. D. Walker, Deputy Regional Administrator A. F. Gibson, Director, Division of Reactor Safety C. A. Julian, Chief, Operations Branch B. T. Debs, Acting, Chief, Operational Programs Section i M. V. Sinkule, Chief, Reactor Projects Section F. R. McCoy, Reactor Engineer
, W. T. Orders, Senior Resident Inspector, McGuire  '
: C. W. Burger, Project Inspector C. L. Vanderniet, Reactor Engineer i b. Members of the Duke Power Company staff met with members of the NRC Region II staff to discuss the status of the McGuire Units 1 and 2 Nuclear Service Water System. A copy of the meeting agenda and DPC handouts appear as Attachments 1, 2, and 3 to this inspection repor DPC representatives stated that, from the information available to the
. DPC staff, the Nuclear Service Water System had been and is currently operable. The NRC staff acknowledged that, once the NRC had surfaced concerns regarding the Nuclear Service Water System, the licensee has placed extensive resources on solving the proble As a result of the aforementioned meeting, NRC representatives contacted DPC staff on March 24, 1986, to request additional informa-tio DPC staff agreed to formally submit a response by April 25,
, 1986, regarding the following seven requested item Provide the as-found and as-left RN flow balance test results for
;
all RN train Provide the as-found and as-left VA test results for all containment spray heat exchanger Provide an RN operability determination for early October 1985 when RN flow was recorded as 800 GPM to the 1A containment spray heat exchanger Provide safety evaluation of the January 28, 1986 RN header
,
pressure transien Provide an RN operability determination based on the 1A contain-ment spray heat exchanger throttle valve setting which existed l
      '
,
just prior to the first heat transfer test and based on expected flow under accident conditions prior to heat exchanger cleaning )
cycle )
 
-
Provide the final parameters for use in the LOTIC program and their engineering basis.
 
l
-
Provide DPC plans to prevent a recurrence of these event . -. -. . _ .
 
_-  . - - -
,
 
By memo of April 25, 1986, Duke Power Company responded to these requests. The responses contend that the RN system was continuously operabl Inspectors will follow up on this information during a
    -
future inspectio The resolution of these matters represents unresolved item (369/85-38-06, 370/85-39-06).
 
12. General Conclusions 1 During the operating history of the McGuire plant, the licensee has experi-enced an increasing degradation of the RN system. It is apparent that the licensee has dealt with this situation on a case-by-case basis. Until prompted by the NRC, the licensee had not determined the full extent of the RN system degradation or taken adequate corrective action to preclude i repetitio Although the licensee has recently dedicated significant resources to addressing the problem, serious doubt exists regarding the past operability of the RN system and those safety related systems, such as containment spray, for which RN is an ancillary syste This doubt is fostered as a result of aggregate observations of significantly reduced
; heat transfer capability of various safety related heat exchangers, reduced
, RN flows, improper throttle valve settings, increased corrosion, and lack of
'
adequate preoperational testing. This situation is contrary to 10 CFR 50, Anpendix B, Criterion XVI which requires that measures shall be established tr assure that conditions adverse to quality, such as failures, malfunc-
. tions, deficiencies, deviations, defective material and equipment, and
'
'
nonconformances are promptly identified and correcte In the case of significant conditions adverse to quality, the measures shall assure that
'i the cause of the condition is determined and corrective action taken to preclude repetitio The identification of the significant condition adverse to quality, the cause of the condition, and the corrective action taken shall be documented and reported to appropriate levels of managemen The licensee's failure to meet these requirements, in the case of the RN
,
system, is a violation (369/85-38-05, 370/85-39-05).
 
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. . _ - _ . .
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ATTACHMENT 1
!
DUKE POWER /NRC REGION 11 i
MEETING TO DISCUSS McGUIRE NUCLEAR STATION NUCLEAR SERVICE WATER SYSTEM PERFORMANCE MARCH 14, 1986 AGENDA
* OPENING REMARKS  GERALD VAUGHN
* OVERVIEW OF NUCLEAR SERVICE WATER SYSTEM NEAL McCRAW i
'
* NUCLEAR SERVICE WATER SYSTEM EXPERIENCE TONY McCONNELL
* RECENT OPERATIONAL EXPERIENCE  BILL SUSLICK (10/04/85 TO PRESENT)
* DESIGN CONSERVATISMS  BILL KRONENWETTER
!
* CLOSING REMARKS  GERALD VAUGHN
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          .
      ! i '.: .
^*
 
NUCLEAR SERVICE WATER SYSTEM EXPERIENCE ESTABLISHMENT OF BASIS FOR RN SYSTEM OPERABILITY
  * RN SYSTEM PRE-OPERATION FUNCTIONAL TEST COMPLETION DATES 7/25/79  -
UNIT 1 i
11/12/82  -
UNIT 2
  * NRC PRE-OPERATIONAL INSPECTION DATES COVERING RN SYSTEM TESTING 11/03/78  -
UNIT 1  INSPECTION REPORT 369/78-33 8/16/83  -
UNIT 2  INSPECTION REPORT 370/82-19
  * SURVEILLANCE TESTING IMPLEMENTATION DATES a
1/06/80  -
UNIT 1, TRAIN A 2/06/80  -
UNIT 1, TRAIN B
,  2/22/83  -
UNIT 2, TRAIN B 2/23/83  -
UNIT 2, TRAIN A IWV AND IWP TESTING WOULD HAVE BEEN IMPLEMENTED DURING THESE TIME FRAME * THE PRE-OPERATIONAL TESTS, lWP TESTS, IWV TESTS AND ESF TESTS WERE OUR STANDARDS FOR ESTABLISHING AND MAINTAINING RN SYSTEM OPERABILIT . MAINTENANCE OF COMPONENTS BASED ON MONITORING OF OPERATIONAL PARAMETERS
  *
REFER TO LIST OF EQUlPMENT CLEANINGS
  *
PERFORMANCE MONITORING PROGRAM BEGAN DEVELOPMENT IN MARCH, 1984      l l
l
________ _ -  - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _
 
' t
''.
Ill. BEGAN EVALUATING RN SYSTEM HX'S FOR FOULING EVEN THOUGH THERE WERE NO INDICATIONS OF FOULING
*
DATE WHEN UNIT 1 COMPONENT COOLING (KC) HX'S WERE EVALUATED FOR FOULING WITHOUT INDICATIONS OF A FOULING PROBLEM 9/01/84
* DATE WHEN KC HX'S WERE CLEANED 11/84 - UNIT 1 6/85 - 7/85 - UNIT 2
* EVALUATION AND INSPECTION / CLEANING DID NOT DETERMINE THAT KC HX'S WERE INOPERABLE IV. RN SYSTEM OPERABILITY REEVALUATION BASED ON 1A RN PUMP TEST RESULTS
*
DATE WHEN A FLOW MEASUREMENT PROBLEM ON 1A RN PUMP WAS IDENTIFIED 10/04/85
*
A REEVALUATION OF OPERABILITY CRITERIA WAS BEGUN TO REFOCUS OPERABILITY CONCERNS FROM THE RN PUMP TO THE RN SYSTEM AS A WHOLE V. ACTION ITEMS RESULTING FROM REEVALUATION OF RN SYSTEM OPERABILITY CRITERIA
*
BEGAN THE PERFORMANCE MONITORING PROGRAM ON l  RN HX'S ON 11/01/85
*
'
THE RN SYSTEM TESTING PLAN WAS SUBMITTED TO REGION 11 ON 12/01/85
*
THE UPDATED RN SYSTEM TESTING PLAN WAS SUBMITTED TO REGION ll TO INCLUDE TESTING OF ALL 62 RN HX'S AND RESOLVE 1A RN PUMP FLOW INDICATION PROBLEM ON 12/18/85
! NOTE: IN ALL THE TESTING AND ANALYSIS DONE IN 1985, WE DID NOT DETERMINE THAT ANY OF THE HX'S EVALUATED WERE INOPERABLE.
 
f
 
_ _ _ _
, .,
,
't EQUIPMENT CLEANINGS  j
      !
*
LOWER CONTAINMENT VENTILATION HX FOULING WAS IDENTIFIED AS ONE OF THE FACTORS IN THE LOWER CONTAINMENT COOLING PROBLEM 10/22/82 NOTE: (A) FOULING OCCURRED AT LAKE TURNOVER IN THE FAL ONLY TIME WE HAD TO CLEA (B) BIOFOULING WAS EVIDENT DUE TO HOT AIR ON SHELL SID *    '
CONTROL ROOM VENTILATION (SHARED BETWEEN UNITS 1 AND 2)
TRAIN A  TRAIN B 11/19/82  3/83  {
10/03/83  1/07/85 12/19/83  10/21/85 5/30/84  11/05/85 10/31/84 9/25/85 10/24/85 10/31/85
*
PENETRANT / DISPERSANT ADDED TO THE RN SYSTEM IN ATTEMPT TO CLEAN LOWER CONTAINMENT COOLING UNITS 4/27/83
*
REACTOR COOLANT PUMP MOTOR COOLERS UNIT 1  UNIT 2 12/31/84  8/10/84 11/08/85
 
    .
ASSUMPTIONS ALL SAFETY RELATED EQUIPMENT REQUIRE FLOWS CONCURRENTLY 5
    "
THROUGHOUT DESIGN BASIS EVEN g
 
s
 
m HEAT EXCHANGERS DESIGNED FOR MAXIMUM POND TEMPERATURE OF 95 F.
:
 
FLOW AND FOULING DESIGN MARGIN AFFECTS ON CONTAINMENT PEAK PRESSURE (CONTAINMENT DESIGN = 14.9 PSIG)
(x10bfuHROF) (x10bIUHROF) tbs T0 OfE'
CLEAN OfFFkbfEik 5.18  8.11 5000 8000 -
DESIGN (FSAR) 2.94  5.00 5000 8000 12.36 75% NS DEGRADED FROM DESIGN 0.735 5.00 5000 8000 14.42 REDUCED FLOWS DEGRADhDHXs 1.47  2.98 3800 6000 13.59 0 = U3 (LMTD)
U = (-00 LING, FLOW)
 
  .  ..
l-
.g
.
NUCLEAR SERVICE WATER ESSENTIAL COMPONENT FLOW REQUIREMENTS  ;
,
 
DESIGN F OWS  !hkE COMPONENT  (FSAR  AChl0WS KD Hx  900  900 KC Hx  8000  6000 i
NS Hx  5000  3800
      ,
VC/YC CONDENSER  775  775 I
KF ES COOLER  20  15 NS ES COOLER  45  20 ND ES COOLER  45  20
:
NV PUMP COOLERS  28  15
      ;
; NI PUMP COOLER  20  20 i
i
!
<
, + , . _ _ . -- n - - - - - - -- ,, - - - - . ,. , ,-.----.,,--,.-,.-- K ,*. ,,
ADDITIONAL DESIGN MARGINS LOWER SNSW POND TEMPERATURE HIGHER ICE WEIGHT LOWER RWST TEMPERATURE
        .
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . . . _ . - _ . _ _ _ _ _ . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _____
w -
 
.- -
,. ,
a
,,  ATTACIGIENT 3 i
T. .  <
PERFORMANCE MONITORING PROGRAM
* Reliability. Efficiency and AvaiIabiiity
* Monitors the overall health of equipment
* Development begun in March. 1984
* Tangible results already being reaIized
     .
     .
Company and Mr. R. Walker of my staff on November 12, 1986, concerning an Enforcement Conference to be conducted at the Region II office on December 8, 1986, at 1:00 p.m. We requested this meeting to discuss our findings relative to operability concerns that were raised over the past operation of the nuclear service water system (RN) at the McGuire Nuclear Station. These concerns were stated in the Region II inspection report Nos. 50-369/85-38 and 50-370/85-3 The specific issues of concern which should be addressed at the conference appear in the enclosed Enforcement Conference agend Should you have any questions regarding these arrangements, we will be pleased to discuss the


. 3' .
Sincerely, (original signed by M. Ernst)
l'
J. Nelson Grace Regional Administrator Enclosure:
  .
Proposed Meeting Agenda cc w/ encl:
NUCl. EAR SERVICE WATER PUMP (RN) 1A
  ' , L. McConnell, Station Manager bec w/ encl:
  * RN Pump 1A did not meet its quarterly IWP acceptance criteria (10/4/85)
\NRC Resident Inspector Document Control Desk State of North Carolina N D. Hood, NRR RII  RI  RII  RI B CJttlan AFGibson R0 Walker o //3 11/ 36 11//L/86 11/g4186 11//9/86 g1250557861113    [
* Replaced impeller (10/5 - 10/6/85)
g ADOCK 05000369 PDR  _,
* Performed new pump head curve /lWP baseline test (10/7/85)
* Troubleshooting
* Evaluated the pump acceptance criteria based on the actual system demand
* Conducted the pump head curve using the 2A and 1A KC flow elements in series with the 1A RN flow element
* Using the most conservative head curve results 1A RN pump was declared operable (10/11/85)
* Optimum replacement was a calibrated 84" flanged spool-piece with a 0.831 beta ratio orifice
* Installation (February 26-28,1986)
* 1A RN Pump head curve conducted with new flow element (March 3, 1986)
** Summary - The pump was never inoperable, fouling of the flow element resulted in errors in the conservative direction.


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CONTAfNMENT SPRAY (NS) HEAT EXCHANGER
  * 1A NS Heat Exchanger had a high differential pressure
  * Commission expressed concerns of biological attack of s t a i ti l e s s steel
  '
tubes
  * Testing Performed:
1. Structural Integrity Test 2. Minute Leakage Test Heat Balance Test
  * Structural Integrity and Minute Leakage Test indicated insignificant leakage
  * Visual Examination of the tubes
  * Heat Balance Testing quantified the extent fouling had occurred
"
  * Peak Containment Accident Pressure CLOTIC) calculations showed the heat exchanger could still perform its function
  * Cleaning iterations
  * Tested and cleaned the other NS heat exchangers based on 1A experience
  * * Summary:
1. NS Heat Exchangers are intact 2. The NS Heat Exchangers were fouled; however reanalysis proved operability j
.
----gc* - -
y e,- ---- --e- - m --pq a--n-- - me---w --e,--r 1 =ya---e- -~ ------e-- P
_ . . _ . _  . _ .
_ _ _  _ _ _ - *
      .*
      . , , ,
._
Containment Spray lleat Exchanger Testing i
t i
.,
  *  lleat Exchanger
  .
    ,
    ,
~
I i
Temperature)
:
m  i  Y  a I i  'f
,
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,
ENCLOSURE PROPOSED MEETING AGENDA DECEMBER 8, 1986 AT 1:00 Opening Remarks  J. Nelson Grace I Issues of Concern  R. D. Walker Duke Power Representatives Discuss the January 27, 1986, event which resulted in the cavitation of the RN pumps and resultant RN system low flow conditio What bearing did this event have on past system operability? Discuss RN system preoperational testin . Why the McGuire Units 1 and 2 RN systems were not tested in a design basis accident configuration prior to January 27, 19867 > Why were preoperational RN component throttle settings incorrectly translated to operating procedures? Why preoperational tests did not verify requisite RN flow to Units 1 and 2 control room air conditioners? Discuss the 10 CFR 50.59 evaluation which permitted the cross-connecting of RN system trains 1A and 2A in early October 198 How did that evaluation meet the criteria of 10 CFR 50.59? Discuss why Duke Power Company did not perform a formal engineering evaluation of the December 17, 1985, RN flow test results until January 1986? Discuss the quarterly 1A containment spray heat exchanger differential pressure test performed on October 7, 198 . What was the significance of the as-found RN flow of 800 gpm relative to past 1A containment spray heat exchanger operability? What was the significance of station's inability to achieve a 5000 gpm test flow?
!
Containment Spray Pump    Flow f
I
!
>
    )/
FWST


  (400,000 gal.)
'
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.
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,
*
"
. McGuire Nuclear Station
'
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  ... .... ....
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36
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_ _ - . .-. . _ . - _ _ - _ _ - . _ . - , ,
___ _ ___ .
l*
'
s P
e OTHER HEAT EXCHANGERS and FLOW BALANCE
* Began evaluation and procedure generation for testing essential heat exchangers (10/24/85)
* 1A Train RN flow balance performed aligned to low level intake (12/17/85)
* 1A NV Pump Speed Reducer Oil Cooler cleaned (12/20/85)
* Conducted test using NSWP as suction (1/27/86)
* Inadequate flow to some heat exchangers
* Reanalyzed the necessary flow rates to the KC and NS heat exchangers
* Design review of alignment configuration to properly conduct flow balance to meet all design assumptions
* Conducted the 1A Train flow balance throttling flow to the KC and NS heat exchangers, aligned to NSWP with 6000 gpm supplied to other unit (1/28/86)
* Performed other flow balances (1/30 - 2/28/86)
* Began extensive cleaning, testing and inspections of all essential heat exchangers (2/3/86)
Total Cleaned / Tested / Inspected: 54 Total Number of Hea t -Ex change r s : 62
** Summary:
Cleaning and testing of all essential RN system components is on schedule to meet March 31, 1986 completion
  .-  . _ - _ - . - . .- - __ - . - -- - . _
d
.
.
.
%
s
-
.
l i
i    ATTACHMENT 4
!
't NRC Inspection Team Confirmatory VA Calculations
.
: Calculations were performed to evaluate the containment spray heat exchanger UA j value used in containment pressure calculations performed by Westinghouse for
; Duke Power on November 28, 1985 and January 17, 1986. The following nomenclature is used in the subsequent calculations:
:
.
Nomenclature i
,
,
A -
  -.
heat exchanger area
Enclosure   2 Why the governing procedure, PT/1/A/4403/04, lacked qualitative or quantitative acceptance criteria? In retrospect considering all the information obtained from RN system testing, discuss the overall operability of the RN system prior to the implementation of corrective action Discuss the lessons learned, the current status of the station's RN systems, and future corrective action .
;
e A-e-w-------r------- -,.- ,s,.s. r-,------- - - , - - - - - - - - - - - - . - - - r---- - -.- r-,
Di -
tube inside diameter i Do -
tube outside diameter
.
i 1 Fi -
tube inside fouling factor Fo -
shell side fouling factor
:
F oAPP
  -
appropriate shellside fouling factor i
i G -
mass flux
 
! hi -
tube inside heat transfer coefficient ho -
shell side heat transfer coefficient  i
! K -
water thermal conductivity  ,
K -
stainless steel thermal conductivity ss
; Pr -
water Prandtl number
 
Re -
Reynolds Number GD D
l    y
      '
:
i oFo --
two standard deviation uncertainty in Fo u
  -
liquid viscosity
!
t
!
f
'!
l i _ _ _ ..____._ _ _ _._. _. . _ _ _ . _ _ _ _ -_ ._ _ _ _ _ _ _ _ ._.. _ -_ _ _ ..- _ _ a
 
. _ _ . . __ _ . . ._ .  . . . - . _ -.
;.
i-
!
:
1 -. Attachment 4   2 i
!
J j  The UA design value for this heat exchanger is 2.95 x 105 Btu /h/ F while Duke provided Westinghouse with a degraded value of 7.35 x 10' Btu /h/ F, 24.9% of the design value. Experimentally determined UA (11/22/85) values indicated that the actual degraded value was ~8.77 x 10' Btu /h/ F, 29.7% of f
the design valu Confirmatory UA calculations were performed by initially determining a f  design heat transfer coefficient for the shell side of the heat exchanger.
 
I  This was done by using design value fouling factors, and assuming that the I  tube side heat transfer was correctly predicted by the McAdams equation at j  the design condition ,
'
hiDi k =0.23 ReD.8Pr 1/3
  .    (1)
;  The UA for the heat exchanger is
!  UA =  A    (2)
;  1_ + pg 1_ + F4 po + F o +D g In p g hg Di hi Di 2K ss UI
;
For the design condition, all values (including UA) are known except hg ,
[  which was determined to be 918 Btu /h/ F/ft2 using equation (2).
 
The information supplied to Westinghouse by Duke was acquired from experi-
;  mental testing of heat exchanger 1A on 11/22/8 The data from this e<periment was used to determine an appropriate value for the degraded UA by
'
j  first determining the as-tested fouling facto In order to do this, i  experimental flow rates, temperatures, etc. had to be used to determine both tube side (h4 ) and shell side (ho) heat transfer coefficients appropriate
!  for the test. Tube side heat transfer coefficients were determined using i  equation (1) evaluated at the test condition Shell side heat transfer i  coefficients were assumed to scale as:
    *
Pr
 
f  hg po - Re D i  K      (3)
j  This equation is used frequently in determining shell side heat transfer for
'
shell and tube heat exchangers. Equation (3) was evaluated at both design and test conditions, and an hg for the test was calculated from the design h, determined above. Equation (2) was then used to determine the fouling
:
factor appropriate for the shell side under as tested conditions assuming
!  the tube side fouling factor is the design value of .0005 (this assumption
;  actually has no impact on the final VA since the two fouling factors are not
 
'
a function of flow and fluid conditions). The shell side factor was determined to be F
g
  = .00912    (4)
          ,
. - -
Y    -. - _ - - - - - , . , , -
        . . . , . ,
 
  -_ - . - -   . - . - ___ - - _  _ __  -
.
.
.
l Attachment 4
              '
.        3
,
l l
for the experiment vs. the 0.001 design valu In addition to this calculations, the experimental error associated with the testing equipment and procedure was used to determine an uncertainty value for F . gThis calculation was performed using propagation of errors (see for example
!  Beers,1957, " Introduction to the Theory of Error") through the equation
;  (5), the energy balance on the NS side of the heat exchanger (only the NS flow was used to determine overall heat flow).
 
'
o Q = mCp (T out  -Tin)    (5)
The uncertainty in temperature measurements were given to the NRC team by licensee representatives as    .4 F including both RTD, and signal conditioning equipment error. These RTD's were apparently calibrated before testing, which increases confidence in the temperature measurement Additionally, errors in the flow measurements were also included. Handbook uncertainty values for uncalibrated orifice plates are typically 1%-2.5% of measured flow. In addition to this, there are uncertainties associated with the other instrumentation necessary to make the flow measurements (DP cells,
)  readouts,etc.). The orifice plate was an uncalibrated process device so it was estimated the overall uncertainty was ~5% of the measured value. Each of the uncertainties stated above were treated as one standard deviation
.
  (lo) uncertaintie It is believed that a two standard deviation (2o)
i  uncertainty bound should be applied in order to insure conservatism (two standard deviations give a 95% certainty of the measurement). The 2a value 4  for Q was found to be ~12%. Additionally, since design heat flow was based i  solely on calculations and not on tests. It was assumed that a 2.5% error (lo value) was present in the design heat flow determination. It was also assumed that equations (1) and (3) could be used to correctly scale with temperature level and flow rate (0 uncertainty was assigned to this
;  process). The two errors above, experimental and design, were used to determine overall error in F by    g propagating errors through the calcula-
'
tions described abov The two-standard deviation uncertainty in F was o
 
determined to be:
oF g = .00149      (6)
i  for the uncleaned case of heat exchanger 1-A. An appropriate UA value for the Westinghouse calculations was then determined by using:
FoAPP = F  g + oF g      (7)
i  These values were determined for three cases:    unit 1-A before cleaning, unit 1-A as it existed after last cleaning, and unit 2-B. The table below
;  summarizes these results (in all cases, RN flow was assumed to be 4800 gpm).
 
J
-_ - -. . - . - . - - _ _ . _ _ _ _ - - _ - , . , _ _ . - - _ _ - - - . _ - _ - .   - - - _ . _ - , _ - . - _ , . , _ _ - -
 
.
'.
*
,
Attachment 4  4 Summary of Calculations UNIT  STATUS  F g oFo UA 1-A uncleaned (11/22/85) .009 .0015 8.18 X 105 1-A cleaned (01/16/86) .0033 .0007 1,63 X 105 2-8 uncleaned (01/24/86) .011 .0127 7.16 X 10'
Westinghouse input  7.35 X 105 The UA value calculated for the 2-B uncleaned case is slightly below that given to Westinghouse on 11/28/85 and 01/17/86. However, if the containment pressure calculations performed on 01/17/86 are used as a starting point, and the containment pressure change with VA change is similar to that noted in the 3 calculations performed on 11/28/85, the peak containment pressure can be estimated for a UA value of 7.16 X 105 These calculations estimate that the peak containment pressure for this UA value would be approximately P = 14.56 psig, still below the 15 psig limiting valu The calculational methods used to evaluate heat exchanger performance appear to be reasonable. However, when calculations are being performed to deter-mine heat exchanger performance at reduced flow, it is also necessary to apply appropriate fouling factors to heat exchangers which are suspected of being fouled. This has not been done in previous Duke calculations. As an example, the inspection team looked at the charging pump speed reducer oil cooler. Duke has found the oil inlet temperature to increase from 141'F to 166 F when RN flow to the heat exchanger is reduced from 20 gpm to 10.7. _In addition to the reduced water flow, the effect of fouling should also be considered. Confirmatory calculations were performed assuming both reduced flow and a fouling factor of ~.008 on the RN side and .001 on the oil side (design fouling factors were presented as a sum of Fg +F4 =.0025). The RN fouling factor is an estimate based on findings in the uncleaned containment spray heat exchanger (F, =.009) and recognizing that continuous water flow through the oil cooler might reduce fouling somewhat. A summary of the maximum oil temperatures is presented in the following tabl A calculation with the RN cooling water temperature reduced to 65 F is given to demonstrate the cooling water temperature effect on heat exchanger performanc As can be seen in the below table, the reduction in RN temperature from 95 F to 65 F has a significant impact on oil temperatur A similar effect would be seen in other heat exchangers in the train (although not exactly the same magnitude).
 
Comparison of 011 Cooler Assumptions Cooling Water Inlet Tem Flow (gpm) F
 
T oj) ( F)
95 F (Design)  20 .0015 141
  '95'F  1 .0015 166 95*F  1 .008 185 65'F  1 .008 155
}}
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Latest revision as of 15:56, 18 December 2021

Confirms 861208 Enforcement Conference in Region II Ofc to Discuss Findings Re Operability Concerns of Nuclear Svc Water Sys as Noted in Insp Repts 50-369/85-38 & 50-370/85-39,per 861112 Telcon.Proposed Agenda Encl
ML20214G095
Person / Time
Site: McGuire, Mcguire  Duke Energy icon.png
Issue date: 11/13/1986
From: Grace J
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To: Tucker H
DUKE POWER CO.
References
NUDOCS 8611250557
Download: ML20214G095 (3)
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November 13, 1986 Docket Nos. 50-369, 50-370 License Nos. NPF-9, NPF-17 Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:

SUBJECT: CONFIRMATION OF MEETING ARRANGEMENTS - MCGUIRE NUCLEAR STATION DOCKET N05. 50-369 AND 50-370 This confirms a telephone conversation between Mr. H. Tucker of Duke Power

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Company and Mr. R. Walker of my staff on November 12, 1986, concerning an Enforcement Conference to be conducted at the Region II office on December 8, 1986, at 1:00 p.m. We requested this meeting to discuss our findings relative to operability concerns that were raised over the past operation of the nuclear service water system (RN) at the McGuire Nuclear Station. These concerns were stated in the Region II inspection report Nos. 50-369/85-38 and 50-370/85-3 The specific issues of concern which should be addressed at the conference appear in the enclosed Enforcement Conference agend Should you have any questions regarding these arrangements, we will be pleased to discuss the

Sincerely, (original signed by M. Ernst)

J. Nelson Grace Regional Administrator Enclosure:

Proposed Meeting Agenda cc w/ encl:

' , L. McConnell, Station Manager bec w/ encl:

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ENCLOSURE PROPOSED MEETING AGENDA DECEMBER 8, 1986 AT 1:00 Opening Remarks J. Nelson Grace I Issues of Concern R. D. Walker Duke Power Representatives Discuss the January 27, 1986, event which resulted in the cavitation of the RN pumps and resultant RN system low flow conditio What bearing did this event have on past system operability? Discuss RN system preoperational testin . Why the McGuire Units 1 and 2 RN systems were not tested in a design basis accident configuration prior to January 27, 19867 > Why were preoperational RN component throttle settings incorrectly translated to operating procedures? Why preoperational tests did not verify requisite RN flow to Units 1 and 2 control room air conditioners? Discuss the 10 CFR 50.59 evaluation which permitted the cross-connecting of RN system trains 1A and 2A in early October 198 How did that evaluation meet the criteria of 10 CFR 50.59? Discuss why Duke Power Company did not perform a formal engineering evaluation of the December 17, 1985, RN flow test results until January 1986? Discuss the quarterly 1A containment spray heat exchanger differential pressure test performed on October 7, 198 . What was the significance of the as-found RN flow of 800 gpm relative to past 1A containment spray heat exchanger operability? What was the significance of station's inability to achieve a 5000 gpm test flow?

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Enclosure 2 Why the governing procedure, PT/1/A/4403/04, lacked qualitative or quantitative acceptance criteria? In retrospect considering all the information obtained from RN system testing, discuss the overall operability of the RN system prior to the implementation of corrective action Discuss the lessons learned, the current status of the station's RN systems, and future corrective action .

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