IR 05000338/1989022

Insp Repts 50-338/89-22 & 50-339/89-22 on 890601-0714.No Violations or Deviations Noted.Major Areas Inspected:Plant Status,Maint,Surveillance,Esf Walkdown,Operational Safety Verification,Generic Ltr 88-17 & Plant Startup

ML20246M745
Person / Time
Site:	North Anna
Issue date:	08/24/1989
From:	Caldwell J, Fredrickson P, King L, Munro J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20246M719	List: IR 05000338/1989022 ML20246M714
References
50-338-89-22, 50-339-89-22, GL-88-17, NUDOCS 8909070241
Download: ML20246M745 (17)

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• WM o UNITED STATES

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RE210N il y j; 101 MARIETTA STREET, '

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, Report.Nos.: 50-338/09-022 and 50-339/89-022

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Licensee: Virginia. Electric & Power Company Richmond,.VA 23261

' Doc'ket Nos.: 50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2 Inspection' Conducted: June , 1989 - July 14, 1989 Inspectors: .$ M ,Ju f/E/f9 J. L. Caldwell enio Resident Inspector D' ate / Signed

' huh h, Blu/n L. P.~ King, Resident nspector Date' Signed

'M, SXon>6 Je 9lLsl29 J.F.Munro,ResidentgInspector Bate' Signed Approved by: sde/e f ei P. E. Fredricksbn, Section Chief Vate' Signed Division of Reactor Project SUMMARY Scope:

'This routine inspection by the resident inspectors involved the following areas: ' plant status,- maintenar.ce, surveillance, engineered safety feature walkdown, operational safety verification. review of inspector follow-up items, Generic Letter 88-17 and plant startu During _ the performance of this inspection, the resident inspectors conducted reviews of the licensee's backshift operations on the following days: June 5, 7, 14, 20, 21,'22, 23, 25,

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26, 28, 29, 30. July 1, 11, 12, and 1 Results:

Within the areas inspected, one' unresolved . item was identified pending the licensee's determination of a safety evaluation concerning a jumper installed on a radiation monitor (paragraph 3).

A weakness was identified concerning the licensee's ability to maintain the operability of various radiation monitors. The inoperability of these monitors reduces the operator's ability to detect, diagnose and isolate radioactive leak '39070241 890823 PDR ADOCK 05000338 O PDC -

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l REPORT DETAILS Persons Contacted Licensee Employees ]

• Bowling, Assistant Station Manager J. Downs, Superintendent, Administrative Services

'*R. Driscoll, Quality Control Manager l

• R. Enfinger, Assistant Station Manager G. Gordon, Electrical Supervisor D. Heacock, Superintendent, Engineering

• G. Kane,; Station Manager

• P. Kemp, Supervisor, Licensing

• J. Leberstein, Licensing Engineer T. Porter, NSE Supervisor

• C. Snow, Superintendent, Technical Services (Acting)

L *J. Stall, Superintendent Operations

• A. Stafford, Superintendent Health Physics F, Terminella, Quality Assurance Supervisor D. Thomas, Mechanical Maintenance Supervisor

• Matthews, Superintendent, Maintenance G. Flowers, Configuration Man 6gement Supervisor Other licensee employees contacted included engineers, technicians, ,

operators, mechanics, security force members, and office personne * Attended exit interview NRC Regional Management Site Visit: On June 8, the Director, Division of Reactor Projects, Region II, visited the North Anna Power Station to interface with the resident inspectors, tour the station and meet with Station Managemen On June 8, at the invitation of the licensee, a Russian delegation toured the North Anna Power Statio The delegation was primarily interested in the licensee's programs involving fire l protection and erosion / corrosion contro Acronyms and initialisms used throughout this report are contained in the last paragrap . Plant Status On June 1, the beginning of the inspection period, Unit I was defueled and in day 94 of the. outage. On June 9, fuel onload commenced and was completed on June 12. The reactor vessel head was set and the unit entered Mode 5 on June 19. Also on June 19, the Flow Test of Inside Recirc Spray Pumps" was satisfactorily completed. On June 24, the 1H EDG tripped while being unloaded during a surveillance test. The #7 upper piston / connecting rod assembly was found to be no longer attached to the crankshaft. Damage was sustained to the connecting rod, upper crankcase j l

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• { and- crankshaft (see paragraph 3 for details). On June 26, during

performance 'of the SSPS Train "B" Slave Relay Response Time Test '

(1-PT-36.5.2), the IJ EDG was inadvertently auto-started. A four-hour-report was made to the NRC in accordance with 10 CFR 50.72 (see paragraph'

L 6 for' details). On June 29, containment pressurization in accordance with the . Type "A" test procedure commence The Type . "A" test. was -

satisfactorily completed and' containment depressurized and returned to atmospheric. pressure on July 4. . On July 7, during the performance of the SSPS Train "A" Slave Relay Response Time Test (1-PT-36.5.1), SW pump 2-SW-P-1A was inadvertently started. A.four-hour report was made to the NRC in 'accordance with '10 CFR 50.72 (see paragraph 6 for details).

Corrective maintenance and test runs were completed by July 10 on.EDG I EDG 1H was returned.to operable status on July 11 following completion of its 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run and ' associated blackout tes On July 13, the unit entered Mode 4 in preparation for unit startu On June 1, the beginning'of.the inspection period, Unit 2 was operating at 100% power, day 25 of continuous on-line operation. On June 7, during the performance of a safeguards ventilation procedure, it was discovered that the filter bypass dampers did not actuate properly. Safeguards exhaust was lined up through the; filter and a four-hour report was made to the.NRC in accordance with 10 CFR 50.72. The safeguards ventilation system was returned to.a normal line-up after completion of maintenance by June 1 On July 14, the end of the inspection period, the unit continued to operate at 100% power, day 68 of continuous on-line operatio . Maintenance (62703)

Station maintenance activities affecting safety-related systems and components were observed / reviewed to ascertain that the activities were conducted in accordance with approved-procedures, regulatory guides and industry codes or standards, and in conformance with TS . EDG Testing On June 24,1989, at 1720 hours0.0199 days <br />0.478 hours <br />0.00284 weeks <br />6.5446e-4 months <br /> during the performance of 1-PT-82-14, the 1H EDG tripped while being unloaded. The trip was caused by low lube oil pressure as indicated by the actuated alarms. On entering the diesel room, the operator discovered that lube oil had sprayed from 2 small holes in the top diesel motor cover. Following removal of the cover, further investigation indicated that the bearing cap had separated from the number 7 upper connecting rod and the rod had separated from the crank and gouged the upper crankcase. The connecting rod was bent, the bearing cap bolts were broken, the bearing shell was destroyed, and the upper piston and top of the cylinder liner were broken. Both connecting rod bearing cap bolts had broken close to the rod-cap interface line. The lower end of one bolt was tightly jammed in its hole in the connecting rod. The upper end of the same bolt, with nut and part of the cotter pin in place, was removed from the upper crankcase. Both pieces of the other bolt were found in the upper crankcase. The cotter pin was missing from

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the upper end of this bol The cotter pin had broken off at the point where it had been bent around the nu The upper crankshaft was removed and sent for an alignment chec It was determined to be off by approximately 15 mils. A new crankshaft was obtained and installed. On June 28, 1989, the inspector observed a check of the camshaft rotation and a check of the main bearing saddles with a mandrel, which did not indicate any distortio A review of the maintenance on the engine indicated that during the 1987 refueling outage, maintenance was performed on the diesel using MMP-P-EG-4, the preventive maintenance procedure for EDGs. During the performance of this procedure, the upper bearing rod bearing cap nuts were torqued per step 7.28.13. Quality control verification was indicated for this ste The inspector did not note any problems with the completed maintenance procedure. The licensee is having its lab evaluate the failed bolts and cause of failure. Non-destructive examination testing was done on the remaining bolts and no problems were noted. Upon completion of repairs, the EDG underwent "run in" testing and a twenty-four hour load test, which were satisfactorily completed on July 1 b. Radiation Monitor Jumper Installation On July 11, 1989, the inspector noticed that RMS-111, the radiation monitor for the effluent to the discharge canal, was being worked. A jumper was installed, as allowed by the instrumentation procedur The consequence of the jumper being installed involves the failure of the steam generator blowdown pumps to trip or their discharge to be isolated from the discharge canal following a high discharge radiation signa A review of Administrative Procedure 14.1, Jumpers, indicated that the procedure allows installation of temporary jumpers. However, the procedures does not indicate when a jumper installation may necessitate performance of a 10 CFR 50.59 evaluation. Jumpering out this function is a change from the UFSAR which states that the discharge will be continuously monitored. The inspector was also concerned that the HP department was not aware of the status of the equipmen The inspectors requested the licensee to review the situation and determine whether or not a proper safety evaluation was performed and to evaluate the process of assuring that operations and HP are aware of radiation monitor problem This item will be identified as an Unresolved Item 338,339/89-22-01, pending the determination of the performance of a safety evaluatio Radiation Monitors Availability The UFSAR, Section 11.4, assumes that the recirculation spray heat exchangers SW ot.tlet radiation monitors an operable to ensure that any leaks in the heat exch0ngers leading to contamination of the SW system are detected well btlow those representing a hazard to the L____________---- __ --

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publi However, the inspector determined that 2-SW-RM-225, Unit 2

"B" RSHX~ monitor and 2-SW-RM-226, Unit 2 "C" RSHX raonitor were inoperable because their respective sample pumps would not operat Section 11.4.2.9 of the ' UFSAR also states that 1-SW-RM-109 will continuously monitor the SW discharge to the SW reservoir. The inspectors were aware that 1-SW-RM-109 was also inoperable. Although grab ' samples are taken every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to comply with TS for inoperable radiation monitors, the combination of these monitors being inoperable removes the operator's ability to detect and correctly identify a leak in a RSHX, and isolate the discharge to the-environment in a timely manne The replacement sample pumps are on order, but will not be availatde until November 198 The examples of inoperable radiation ' monitors discussed above demonstrate a weakness in the licensee's program for maintaining adequate diagnostic and monitoring capabilities.concerning potential radioactive leaks and the - resulting releases. Even though the licensee is in compliance with TS by taking the grab samples as required, the inoperability of radiation monitors handicaps the operator's ability to detect, diagnose and secure radioactive leaks once they develo Within the areas inspected, one unresolved item was identifie . Surveillance (61726)

The inspectors observed / reviewed TS required testing and verified that testing was performed in &ccordance with adequate procedures, that test instrumentation was calibrated, that LCOs were met, and that any '

deficiencies identified were properly reviewed and resolve On July 2, the inspector witnessed 2-PT-71.1 Auxiliary Feedwater Pump (2-FW-P2) and Valve Test. The recirculation portion of the test was monitored locally and the full flow portion of the test was observed from the control room. The operator encountered some difficulty in the performance of step 6.10, which required reopening the trip valve following completion of the test. Approximately four attempts were made before the trip valve could be successfully re-opened. The difficulty was related to the technique utilized in latching the trip valve to the trip mechanism. A more experienced operator successfully latched the valve and retested it to verify proper operabilit The test was satisfactorily .

conducted in accordance with the procedur The test data was l

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subsequently reviewed and met the acceptance criteria. To ensure system

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operability, the inspector verified that the valves which were l repositior.ed during the test had been properly positioned for their normal standby line-up. The inspector will review the operator's difficulty in reopening the trip valve (Step 6.10) in future inspection On July 7, the inspector witnessed portions of three related surveillance tests, 1-PT-138, 1-PT-57.1A and 1-PT-210, Each of the three surveillance tests required operation of the 1A LHSI pump. Data was

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collected for all three tests during the pump operation, to minimize the 1 i

pump run time and any pump degradation which may result from operating the LHSI pump at low recirculation flow rate The tests were well coordinated by a.specifically assigned operator who ensured all procedural requirements were met throughout. Test results were satisfactor On July 11. tne inspector witnessed the blackout portion of 1-PT-83.4, ;

Blackout of Emergency Bus for Shutdown Loads, for the IJ EDG. The EDG ]

load was lowered from 2500 - 2600 kw to 2000 - 2100 kw to preclude the potential for an inadvertent trip on high lube oil temperature. The EDG was operated at this reduced loading condition for approximately 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> Approximately one hour before the procedurally specified shutdown, the EDG was again leaded to 2500 - 2600 kw. Lube oil temperatures were raised to the approximate value that existed prior to the load reduction. The EDG q was then secured and the normal power supply to the Unit IJ bus was interrupted. This tested the auto start and loading capabilities of the EDG. The test was completed satisfactory and no problems were identifie On July 11 and 12, the inspector witnessed the initial test run for 4 Train A slave relays during the performance of 1-PT-36.5.3, Solid State System Output Slave Relay Test. This test, which was designed to functional?y test certain output slave relays using the Train A and Train B Safeguard Test Cabinets, will allow the licensee to test certain SSPS output slave relays for the first time during the unit operation. The ,

pre-job brief was conducted to review the controls in place for the test and the specific effects of each tested relay with the personnel involved in the tes The test was completed, with only two problems encountered:

1) the test push button on the STC Train A did not actuate the K 630 relay, and 2) pumps 1-RS-P-1A and 1-RS-P-1B incorrectly received a start signal f rom their respective biccking circuit However, the pumps did not start since their breakers were in the test positio The licensee processed a procedure deviation to incorporate additional procedural controls to minimize the potential for unanticipated equipment actuation prior to testing Train B. The licensee will also troubleshoot the cause for the aforementioned STC test relay problem On July 6 the inspector observed portions of 2-PT-91, Containment Penetrations procedure. The inspector observed the operator check various LMC valves located in the electrical penetration area. No problems were identifie Within the areas inspected, no violations or deviations were identifie . ESF System Walkdown (71710)

The following selected ESF systems were verified operable by performing a walkdown of the access.ible and essential portions of the systems:

On July 2 and 5, the inspectors walked down the accessible portions of the quench spray system on Unit 2. Valve checkoff list 2-0P-7.4A and drawing number 12050-FM-91A, Rev. 17, were reviewed. The inspector noted that the 1

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drain valve for PI-QS-203 (no valve number) was not shown or redlined on the control room drawing. However, the valve was listed on the valve checkoff list. The lcensee will be investigating and updating the control room drawings to reflect this valv No other problems were identifie Within the areas inspected, no violations or deviations were identified 6. Operational Safety Verification (71707)

By observations during the inspection period, the irspectors verified that the control room manning requirements were being Nt. In addition, the inspectors observed shift turnover to verify that continuity of system status was maintained. The inspectors periodically questioned shift personnel relative to their awareness of plant conditions. Through log review and plant tours, the inspectors verified compliance with selected TS requirements and LCO In the course of the monthly activities, the inspectors included a review of tL Mcensee's physical security program. The performance of various shifts of the security fcece was observed in the conduct of daily activities to include: protected and vital areas access controls; searching of personnel, packages and vehicles; and badge issuance and retrieval. On a regular basis, RWPs were reviewed and the specific work activity was monitored to assure that the activities were being conducted per the RWP The inspectors kept informed, on a daily basis, of the overall status of both units and of any significant safety matter related to plant operations. Discussions were held with plant management and various members of the operations staff on a regular basis. Selected portions of operating logs and data sheets were reviewed daily. The inspectors conducted various plant tours and made frequent visits to the control room. Observations included: witnessing work activities in progress; verifying the status of operating and standby safety systems and equipment; confirming valve positions, instrument and recorder readings, and annunciator alarms; and observing housekeepin During the inspection period, the licensee experienced two inadvertent ESF actuations due to procedural or personnel error In both cases, the equipment responded as required, the licensee reported the event per 10 CFR 50.72, and corrective action was taken to prevent recurrence. The first event, which involved the inadvertent start of the IJ EDG, occurred on June 26 during the performance of 1-PT-36.5.2, Reactor Protection and Engineered Safety Feature Response Time Testing - Slave Relays (Train B).

The cause of the automatic start of the IJ EDG was attributed to the manipulation of the volt meter used during the test. When the instrumen-tation technician changed the scale from VAC to VDC he had to pass through the current scale. The momentary stop at the current scale provided a short across the EDG start relay K-611 and auto started the ED _ _ _ _ - - - . i

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The second event, which occurred on Jaly 7, involved the inadvertent start of the 2A SW pump (2-SW-P-1A). This event also occurred during the performance of a test similar to the one discussed above, except that the test was for Train A. The actual test was 1-PT-36.5.1, Reactor Protection and Engineered Safety Features Response Time Testing - Slave Relays (TrainA). The cause of this inadvertent actuation was determined to be an inadequate surveillance procedur The procedure stated in  !

Attachment 6.1 that 1-SW-P-1A. the 1A SW pump, would receive an automatic j start signal during the testing of the K-602 rela Since the SRO in charge of Unit i recognized that the 1A SW pump was already operating, he informed the instrumentation technician that it would not be necessary to block the automatic start signal for 1-SW-P-1 However, the procedure was in error in that the pump which would actually be started by the K-602 relay was 2-SW-P-1A, the 2A SW pump. Consequently, the error misled the operator and prevented him from requiring the auto start capabilities of 2-SW-P-1A be blocke Although these events constituted minimal safety significance, they continue to demonstrate a probleci with inattention to detail. These types of problems are not occurring as frequently as in the past and, in each case, the licensee documented the problem and conducted a thorough review to determine the cause and corrective actio No violations or deviations were identifie . Review of Inspector Follow-up Items (92701)

(Closed) IFI 338,339/89-14-05, Review documentation to support power supply modification of slave relay The inspector reviewed the licensee's completed work orders for the 11 relays that received modifications to their power supplies. Therefore, this item is considered close . Generic Letter 88-17, Loss of Decay Heat Removal (TI 2515/101)

On June 20. Unit 1 entered a reduced RCS inventory condition and remained in this condition for approximately 3 days. The licensee's response to >

Generic Letter 88-17, including procedures and controls regarding loss of RHR, had been previously reviewed in April 1989 (see NRC Inspection Report 338,339/89-08 for details). The inspector reviewed procedural changes made as a result of observations and comments discussed with the licensee in April 198 The inspectors also observed the actual drain down evolution of the RCS and periodically monitored procedural compliance during the ensuing 3 days of reduced RCS inventory condition The following is a brief description of these reviews, Procedure Revisions Procedure 1-MISC-37, Assessment of Maintenance Activities for Potential Loss of Reactor Coolant Inventory, has been changed to document maintenance personnel attendance at the pre-job brief.

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l i Procedure MD ADM-11.0, Containment Closure Teams, was written and implemented prior to the drain down of Unit The 4 procedure addresses the designation of the Containment Closure I Team members and their required actions should it be necessary ]

to implement containment closure. The procedure also details l inventory requirements for containment closure tool The I procedure has a potential weakness with respect to lack of {

required pre-shift brief The procedure recommends that team members familiarize themselves with designated boundary jobs, check that an RWP is available for containment closure and obtain required dosimetry. Consideration should be given to formalization of this practice to ensure turnover of requisite information is provided to each Closure Team. However, the i'

licensee's practice.during the most recent evolution was for the Mechanical Foreman to brief each Closure Team, even though not required by procedur , Procedure 1-AP-11.2 Loss of RHR, has been revised to include a reference (a " Note" prior to step 1) to the heatup curves of Attachment b. Observation - Pre-Job Brief and RCS Draining Evolution 4 On June 20. RCS drain down to a reduced inventory condition was completed. The inspector observed the pre-job brief and the actual drain down to approximately 12 inches above nozzle centerline. The briefing satisfactorily addressed all of the items and concerns detailed in Attachment 4 of 1-0P-5.4. The brief was particularly effective in that it was instrumental in identifying the need for a procedure deviation to 1-AP-11.2, Loss of RHR. Specifically, procedure steps 24 and 25 direct cold leg injection be available for the RCS plant conditions in effect during the drain dow This would have been inappropriate since the maintenance to be performed was on cold leg component Also cold leg injection, as the preferred flow path, is contrary to the licensee's response to Generic Letter 1 88-17. This response indicates that "... hot leg injection flow path is preferred, with cold leg injection available as an l j

alternate." The licensee has since revised the procedure to be consistent with their Generic Letter 88-17 respons Steps 24 and 25 were revised to ensure that the preferred method of SI injection is to the hot leg of the RC . Pmcedure 1-0P-5.4 was conducted in a deliberate and professional manner. The operators demonstrated a heightened awareness by continually checking and monitoring applicable RCS, RHR and CVCS parameter . Following RCS draindown to 12 inches above nozzle centerline, the inspector reviewed the turnover proces Procedure 2-MISC-35.1, CR0 Turnover Checklist (Modes 5 and 6), step 7 l

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i requires the offgoing and oncoming CR0s ' to list the operable high head. and low head safety injection pumps and respective flow paths any time RCS level is three feet or more below the vessel flange. The first CR0 Turnover Checklist completed after the drain down evolution did not indicate the HHSI flow path via safety injection valve MOV-1869B. Questioning of the operator indicated that he was fully knowledgeable of the requirement for the HHSI flowpath but did not realize that this flow path was required to be . specified on the turnover checklist. This concern was discussed with the 11censee and subsequent turnover checklists indicated the HHSI . low path to the hot leg Subsequent to the draindown. the licensee developed an additional' turnover checklist that would be performed in conjunction with 1-MISC-35.1. This checklist .is specific to reduced RCS inventory conditions and requires review and/or verification of the plant conditions and procedures pertinent to RCS draindown condition The inspector's overall observation of the licensee's actions with regard to the draining of the RCS was favorable. However, certain aspects of management's pre-planning for this evolution were deficient. As previously explained, the procedural guidance given by the " Loss of RHR" procedure,1-AP-11.2, was inappropriate. This planning aversight should not have occurred since the need for the procedure deviation was previously identified for the analogous procedure on Unit 2 prior to the most recent Unit 2 drain down. In addition, although one charging pump and one LHSI pump were operable, no SI flow path existed due to valve tagouts prior to commencing procedure 1-0P-5.4. The pre-job brief identified this deficiency and had the tag removed from MOV-1869B. The optimum situation is for the management planning process to address these type of problems prior to the commencement of the procedure, rather than relying on the operating shift to catch them during the pre-job brief. The licensee is reviewing the need for further program enhancements, in addition to the procedural revisions previously mentioned. These enhancements would improve entry into the reduced inventory condition and include: Preplanning - Improve the preplanning process between Operations and Planning Department to ensure operability of required equipment prior to commencing the draindow . Training - Operations personnel should receive additional formal training on reduced inventory requirements to ensure complete understandin . PT-91 - The Containment Penetration procedure needs improvements to enhance control of open penetrations during reduced inventory condition . Plant Startup from Refueling (71711)

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The inspector performed a walkdown of the "C" accumulator using 1-0P-7.3A, Safety Injection Accumulators. No problems were noted. The inspector did {

observe however; that 1-SI-146, the makeup valve to the accumulator, i showed indications of a packing lea On July 10, the inspector made a containment entry on Unit I with the licensee to perform 1-0P-1B, Containment Checklist. There were still several open items that needed to be completed to finish the containment checklist. During the entry, it was discovered that the "C" cubicle l exhauster fan was running backwards. Staging was also in place for work on RS-27, which is a weight loaded check valve for the recirculation spray system. The disc stem had become warped while welding the nut in place to prevent it from coming loose. On July 12, the inspector made another containment entry to observe maintenance replace the RS-27 stem and dis The check valve was then Type "C" tested with no further problems. This tour of the containment indicated the "C" cubicle exhaust fan rotation had been corrected and minor cleanup was taking plac . Allegation Closeout Case Number RII-89-A-0030 Background An individual, herein after referred to an alleger, contacted NRC Region 11 and reported several concern A summary of the concerns which are stated in the alleger's letter and the results of the inspector's findings are discussed in the following paragraph Design Drawing Reference To Specification Not Adhered To Concern The design drawing for installing steam generator snubbers referenced Specification NAS 232. No one had a copy of this specification and apparently it was not followed during the new snubber installation wor Discussion The inspector examined DCP 86-10-2 Large Bore Snubber Leak-Before-Break Modification, North Anna Unit 2, and the following drawings which detail the snubber replacement:

Drawing Number N8610-1-1FV17A R1 Steam Generator & Coolant Pump Supports Arrangement Plan Composite Drawing Number N8610-1-1FV17K R2 Steam Generator Lower Support Clevis Assemblies & Details Drawing Number N8610-1-1FV17L R3 Steam Generator Upper Restraint Assembly

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Drawing Number N8610-1-1FV17N R1 Steam Generator Upper Restraint Details Sheet 2

): . Drawing Number N8610-1-1FV20F R3 Reactor Coolant Pump Supports Details Sheet 2 1 Drawing Number N8610-2-M-700 R7 Steam Generator Upper Restraints

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Sheet 1 of 2 and MISC Support Member Unit 2

' Drawing Number 8609-1-M-700 R0 Steam Generator Upper Restraint Sheet 2 of 2 Connecting Rod Assembly-Drawing Number 8610-2-M-701 R1 Steam Generator Upper Restraint Connecting Rod Assembly (Alternate Arrangement)

The inspector also examined Stone and Webster Specification NAS232, Steam Generator and. Primary Coolant Pump Support Installation for North Anna Units 1 and Section 9.0 of this specification covered installing the Hydraulic Snubbing System, i.e., .the original installation of the Milwaukee Cylinder snubbers. A review of the details on the design drawings showed that the installation requirements for the new Taylor snubbers were shown on the drawings. The requirements of specification l NAS 232, though still referenced on the drawings, were not applicable to l installing the new snubbers. The licensee stated that the drawings would

! be updated to show as-built conditions and incorporate any field changes.

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The reference on the drawings to NAS 232 will be clarified to indicate that it does not apply to snubber installation; but still applies to the steam generator and reactor coolant pump support Findings The concern was substantiate Specification NAS232 was not followed for installing the new snubbers. However this has no safety significance since NAS232 was not applicable for installing the new Taylor snubber Repair To Galling In Holes On Steam Generator Rings Concern

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A field change request was written to grind burrs inside one of the holes

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on a steam generator support ring. The burrs resulted from removing a clevis pin which attached a snubber to the support ring. The FCR was initiated before a number had been assigned to the deficiency report, which documented this problem. The alleger was also concerned because this FCR was used as basis to remove burrs on top of the steam generator Support ring when the FCR did not specifically address removing these burr _ _ _ _ _ _ _ - _ _ _- . _ _ . i

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Discussion The inspector examined Deviation Report Number 89-410 which was written on March 6,1989, to document and disposition the problem of gouges on the inside of the pin hole for snubber 2-RC-HSS-3C on the steam ger.erator support ring. The gouges occurred when removing the pin which attached the snubber to the steam generator support ring. The formation of the gouges is referred to as galling and was tha result of wearing away of metal on the support ring due to sliding friction between the two metal surfaces. The galling resulted in small scratches being formed on portions of the support ring steel. Additionally, small burrs protruded above the surface of the support ring steel at the outer edges of the scratches, and on top of the steam generator support ring. The licensee documented the size of the gouges in the support ring on DR 89-410 and issued a FCR, FC 4, to DCP 86-10 on March 13, 1989, for repairing the affected areas. The repair method called for removing the burrs by filing or by using power grinders. The inspector concurred with the licensee's repair method. Although the FCR did not specifically address the burrs on top of the support ring, it was the intent of the FCR to remove all of the burrs. Removal of the burrs on top of the support ring did not reduce the thickness of the rin The licensee assigns numbers to the Deviation Report after they are written for tracking purposes. The fact that the FCR was written prior to assignment of the number has no safety significanc Finding The concern was substantiated. However, this concern had no safety significance. The writing of a FCR to correct nonconforming conditions noted on a deviation report prior to assigning a tracking number to the DR has no safety significance. The licensee's action in removing the burrs caused by the galling complied with acceptable industry practices. The intent of the FCR was to remove the burrs on the inside of the clevis ring hole, and on top of the support rin Steam Generator Bolts not Torqued in Accordance witn AISC Requirements Concern The rear brackets on the lower steam generator / reactor coolant pump supports were attached with eight inch long bolts. The original instr,1-lation requirements for these snubbers in Stone and Webster Specification NAS 232 specified that these mounting bolts were to be tightened to s torque of 1500 foot-pounds. For the installation of the new snubbers, DCP 86-10 specified that these bolts were to be tightened using the turn of the nut method with a 1/4 turn past snug tigh The alleger questioned the adequacy of this design since the American Institute of Steel Construction (AISC) standards specify a 2/3 turn for eight inch and longer bolt i

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Discussion The inspector reviewed DCP 86-10, the associated drawings, and specification iMS 232. DCP 86-10 specified tightening the eight inch long A490 bolts using the turn of the nut method with a 1/4 turn beyond snug tigh Snug tight is defined in DCP 86-10 as the point where the lock washer is deformed by the bolt head and the lock washer is in full contact with the steel and bracket surface. Specification NAS232 specified tightening of the bolts.using 1500 foot-pounds of torque. However, the requirements of NAS232 were superseded by DCP 86-1 AISC requirements for. turn of the. nut method for bolt tightening are specified in Paragraph 5.(c)~and Table 4 of AISC Specification for Structural Joints Using ASTM A325 and A490 Bolts. The specification recommended that bolts with length not exceeding eight inches be tightened 1/2 turn beyond snug tigh However, the AISC requirements did not apply to the bolts connecting the rear brackets to the threaded holes in the steam generator vertical support steel. The design of these connections was unique for this application. The connections were designed as columns which are subjected primarily to axial load with small lateral loads due to self-weight excitation and dead load of the snubber Finding The concern was not substantiated. The installation requirements specified for the connections in DCP 86-10 were adequate. AISC specifica-tion and NAS 232 requirements for tigntening the eight inch long bolts were not applicabl Snubber Cylinder Lug Tightening Sequence Not In Accordance With Specification NAS 23 Concern There were no requirements in DCP 86-10 which specified the tightening sequence to be used for installing the cylinder lugs on the new snubber Specification NAS 232 specified a standard tight .% sequence, but this document was not available to the craft or QC personnel. The craft tightened the bolts using any sequence they wante Discussion As stated above, specification NAS 232 was not applicable to DCP 86-1 The inspector questioned licensee engineers regarding the cylinder lug tightening sequence. These discussions disclosed that the craft requested guidance regarding the tightening sequence to be used for installing the cylinder lugs on the new snubbers, and asked whether it was permissible to use the standard tightening sequence. Licensee engineers stated that they had no preferred method, and that a standard tightening sequence would be acceptabl Findings The et ;rn was substantiated in that specification NAS 232 was not followed for installing of the new snubbers. However this concern has no

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l safety significance since specification NAS 232 was not applicable to the new steam generator installation.

E Use of Commercial Grade Washers in Steam Generator Snubber Installation

Concern The Bill of Materials on drawing number. N8610-2-2FV17K specified comercial grade washers to be installed on the A490 or A354 high strength bolts. AISC specifications call for hardened washer Discussicn AISC Specification, Structural Steel For Buildings, . requires that high strength bolts conform to provisions of " Specification For structural Joints Using ASTM 325 or A490 Bolts." The ASTM specification states that

.the designer shall specify the grade of bolts, washers, and nuts to be used in connections. The commentary to the ASTM specification which provides guidance in the application of. this specification, states that hardened washers are not required in all bolting applications. The primary reason for the washers is to prevent galling of the metal under the turning element of the bolt / nut. The inspector examined the steam generator connection details shown on the OCP 86-10 drawings and concluded that'the installation was acceptable. The use of commercial grade washers in the snubbers installation conforms to AISC/ ASTM requirements for the

. intended applicatio Findings The_ allegation was substantiated in that commercial grade washers were specified for use in steam generator installation work. However, this concern has no safety significance since using commercial grade washers in this application conforms with standard industry practice Conclusions One of the five concerns was not substantiated. The remaining four concerns, although substantiated, had no safety significance. The four concerns which were substantiated were statements of fact regarding the steam generator snubber replacement work. Based on reviewing the design details shown in the DCP 86-10 and DCP 82-12 packages, and examining the work in progress under DCP 86-12 on the Unit I steam generator snubbers, the inspector concluded that snubber installation requirements met NRC requirements. The design details associated with DCP 86-10 were also reviewed' during a special NRC inspection conducted February 13 - 17 and February 27 - March 3,1989, which is referenced as a $50MI inspection, and documented in NRC Inspection Report Nos. 50-339/89-20 Within the areas inspected, no violations or deviations were identifie _ .-_ - --_-___-__-__- _ - _ a

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11. Exit The inspection- scope and ' findings were summarized on July 14 with those persons indicated in paragraph 1.- The inspectors described the areas inspected and discussed in detail the ' inspection results listed belo The licensee did not identify as proprietary any of the material provided to or< reviewed by the inspectors during this inspection. Dissenting comments were not received from the license Item Number Description and Reference 338,339/89-22-01 Unresolved Item - This item remains unresolved pending the ~ licensee's determination of the performance of a safety evaluation for the installation of a jumper on a radiation monito . Acronyms and Initialisms AP Abnormal Procedure Aux Auxiliary CAD Computer Assisted Drawing CAE' Condenser Air Ejector CDA Containment Depressurization Actuation CR0 Control Room 0l.erator DCP Design Change Package DHR Decay Heat Removal DUR' Drawing Update Request EDG Emergency Diesel Generator EP Emergency Procedure ESF Engineered Safety Feature EWR Engineering Work Requests FCR Field Change Request GPM Gallons Per Minute HP Health Physics HHSI High Hecd Safety Injection IFI' Inspector Follow-up Item KW Kilowatt LC0 Limiting Condition for Operation LER Licensee Event Report LHSI Low Head Safety Injection LMC Locked Manual Closed MCC Motor Control Center j

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l MOV Motor Operated Valve MPC Maximum Permissible Concentration MREM Millirem MSSV Main Steam Safety Valve i NRC Nuclear Regulatory Commission l NSE Nuciear Safety Engineering PDTT Primary Drain Transfer Tank  ;

Plant Engineering Services

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PORY . Power Operated Relief Valve

' PROM Programable Read Only Memory-

'PSIG . Pounds Per Square Inch Gauge PT Periodic Test PTSS Periodic Test Schcduling System RCS Reactor Coolant System

RHR -Residual Heat Removal RMS Radiation Monitoring System RSHXL . Recirculation Spray Heat Exchanger RTD Resistance Temperature Detector RWP Radiation Work Permit S/G Steam Generator SALP Systematic Assessment of Licensee Performance SI Safety Injection SNSOC Station Nuclear Saf*ty and Operating Committee SRO Senior Reactor Opert tor SSPS Solid State Protection System STA Shift Technical Advisor STC Safeguard Test Cabinet SW Service Water TS Technical Specification

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TSC -Technical Support Center UE Unusual Event URI Unresolved Item UFSAR Updated Final Safety Analysis Report VCT Volume Control Tank WO Westinghouse Owners Group

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