IR 05000454/1998004

Insp Repts 50-454/98-04 & 50-455/98-04 on 980120-0210. Violations Noted.Major Areas Inspected:Engineering,Technical Support & Self Assessment Activities

ML20217E867
Person / Time
Site:	Byron
Issue date:	03/27/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217E836	List: ML20217E830 ML20217E842 ML20217E867
References
50-454-98-04, 50-454-98-4, 50-455-98-04, 50-455-98-4, NUDOCS 9803310189
Download: ML20217E867 (37)

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f U.S. NUCLEAR REGULATORY COMMISSION i

REGION 111 i

l Docket Nos: 50-454,50-455 License Nos: NPF-37, NPF-66 Report Nos: 50-454/98004(DRS); 50-455/98004(DRS)

Licensee: Commonwealth Edison Company Facility: Byron Nuclear Plant, Units 1 and 2 Location: 4450 N. German Church Road Byron,IL 61010 Dates: January 20,1998 through February 10,1998 Inspectors: Z. Falevits, Reactor Engineer, Team Leader T. Tella, Reactor Engineer D. Schrum, Reactor Engineer T. Ippolito, Scientech Contractor C. Jones, Scientech Contractor Approved by: John Jacobson, Chief Lead Engineers Branch Division of Reactor Safety

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EXECUTIVE SUMMARY I i

Byron Nuclear Plant, Units 1 and 2 l NRC Inspection Report 50454/98004(DRS); 50-455/98004(DRS).

Engineerina i

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The AF battery rack modification was not subjected to design control measures commensurate with those applied to the original design and part of the modification was not completed in the field but the modification was closed out. Two violations were identified in this area. (Section E1.2.1)

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The inspectors determined that the licensee failed to establish an effective process for independent inspection and verification of modification activities affecting quality, such as field installations of safety related exempt changes. A violation was identified in this area. (Sect'on E1.3)

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The emergency diesel generator (EDG) system engineer's interface with the Braidwood EDG system engineer during evaluations for previously untested EDG switches and the subsequent identification of deficient control wiring in the EDG control panel was considered very positive. (Section E1.3)

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Overall, safety related modification packages reviewed by the team were of good j technical quality. However, the team identified concerns relative to modification testing i and modification package closure. An example of a violation was identified in this are !

(Section E1.4)

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The licensee failed to develop an instrument out-of-tolerance process to address ;

repetitive out-of-tolerance problems. A corporate procedure had not been implemente l An example of a violation was identified in this area. (Section E2.1)

. The design and system engineers directly involved with the team in the discussions of technical issues were generally found to be qualified and experienced in their respective positions. Further, the engineers demonstrated pride and ownership of their respective areas of responsibilities. (Sections E2.4 and E4.1)

. The pre-fire plans were not maintained to meet the criteria of 10 CFR 50, Appendix R, and the commitments of NRC branch technical position BTP CMEB 9.5-1, Appendix A,in that the drawings had not been updated for more than 10 years. A violation was identified in this area. (Section F3.1)

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The licensee failed to conduct annual physical exams whose results were used to

assess the fire brigade for unrestricted activity. A violation was identified in this area.

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The audits / assessments conducted by SQV and outside auditors were done well and J I included several significant findings, however, weaknesses in follow up activities were identified. (Section E7.1)

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The engineering self assessments reviewed by the team needed improvement in quality, particularly in design engineering. More guidance was needed for follow up on the findings identified during these self assessments. (Section E7.2)

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lli. Engineering E1 Conduct of Engineering (IP 37550)

The team selected the following systems for a more detailed design review during the inspection: Auxiliary feedwater (AF), Auxiliary building ventilation (VA), and Switchyard (SY).

E1.1 Generic Letter 96-01 "Testino of Safety Related Logic Circuits" Insoection Scoce Prior to issuing Generic Letter (GL) 96-01," Testing of Safety Related Logic Circuits,"

dated January 10,1996, the NRC has documented, in various Information Notices, a significant number of instances involving problems with logic testing of safety-related circuits. The team examined Byron's actions taken to address concerns documented in GL 96-0 Observations and Findings The NRC issued GL 96-01 to: (1) notify addressees about problems with testing of-safety-related logic circuits, (2) request that all addressees implement the actions described in the GL, and (3) require that all addressees submit a written response to the generic letter regarding implementation of the requested action The GL requested that licensee's compare electrical schematic drawings and logic diagrams for the reactor protection system, emergency diesel generator (EDG) load shedding and sequencing, and actuation logic for the engineered safety features systems against plant surveillance test procedures. This was to be done to ensure that all portions of the logic circuitry, including the parallel logic, interlocks, bypasses and inhibit circuits, are adequately covered in the surveillance procedures to fulfill the technical specification (TS) requirements, in a letter to the NRC dated April 19,1996, the licensee committed to implement the actions requested by GL 96-01 at Byron Units 1 and 2, following Byron Unit 1 refueling outage B1R08 which was being completed in February 1998. During review of licensee's actions to address this issue, the team noted that Duke Engineering initial review (completed January 14,1998) of Byron Units 1 and 0 TS surveillance procedures and electrical drawings identified approximately 250 untested contacts in safety-related circuits. The review of Unit 2 was expected to be completed in February 199 The team determined that there was no plan to promptly evaluate and address the untested contacts. The licensee informed the team that, due to an event that occurred at another pressurized water reactor (PWR) in June 1997, which involved inadequate testing of interlock circuitry for the P-11 Permissive, Byron engineering was in the process of informing the NRC that resolution of this issue was being extended to the end of 1998. Following concerns raised by the team regarding prompt resolution of the l Duke Engineering findings, the licensee informed the team that the untested contacts

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l would be promptly evaluated and prioritized as to their safety significance and tested in f a timely manner. The team also discussed this issue with NRR staff involved with GL 96-01 to ensure that this issue was being addressed uniforml I In a related matter, problem identification form (PlF) B1998-00525, dated February 2, 1998, documented that a series of breaker interlock contacts used in Units 1 and 2

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l safety injection (SI) automatic actuation logic circuitry have never been tested. These l circuits were designed to automatically actuate following receipt of a Si actuation signal, while both Units 1 and 2 are in modes 1-4 and the engineered safety feature interunit crosstie breakers are closed (e.g. bus 141 to bus 241). The crosstie configuration is j used during station auxiliary transformer maintenance, planned crosstie evolution or i I

restoration from the EDG to the alternate offsite source. Failure of one of the untested contacts to close while the buses were crosstied and an SI signal was present would result in the automatic load sequencing not occurring. The emergency core cooling system equipment would not have started automatically as designed, but could be started manuall j i Conclusions i The licensee had committed to implement the actions requested by GL 96-01 at Byron Units 1 and 2, following Byron Unit 1 refueling outage B1R08 which ended in February 1998. The team was concerned that there was no plan to promptly evaluate and address approximately 250 untested contacts in safety-related circuits (identified by the licensee since April 1996 and reported in January 1998). The licensee informed the j team that the potentially untested contacts would be promptly evaluated and prioritized j as to their safety significance and tested in a timely manner, in a related matter, PlF B1998-00525, dated February 2,1998, documented that a series of breaker interlock contacts used in Units 1 and 2 Si automatic sctuation logic circuitry have never been teste This item is considered Unresolved pending licensee action to address the untested contacts, issuance of the LER for the February 2,1998 finding and NRC review of licensee actions (50-454/455/98004-01(DRS)).

E1.2 Review of Modifications and Design Changes The team examined 18 mechanical, electrical and instrumentation and control permanent modifications in various stages of implementation. The modification packages generally documented the work to be done and the post-modification testing requirements. The modification packages reviewed clearly described the proposed design changes and justification for the changes and contained 10 CFR 50.59 safety evaluations. The team also reviewed calculations made in support of the design changes. The team reviewed selected set point / scaling change requests (SSCRs),

through which some of these design changes were implemented. In general, the modification packages contained the required design documentation, reviews, and approvals. However, the inspectors identified concerns in several areas examined as noted below:

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l E1.2.1 Incomotete Modification to the AF Battery Rack Insoection Scoce i

The team evaluated seismic calculations for design change package (DCP) #960014 ! Observations and Findings DCP #9600148, " Modify the Mounting Detail for the AF Diesel Racks No.1 AFO1EA-B &

1 AF01EB-B," dated May 1996, reduced the number of anchors and bolts holding the AF Diesel Battery rack to the floor from 32 to 8 for two existing rack (1) 10 CFR Part 50, Appendix B, Criterion lli states, in part, that design control i measures shall be provided for verifying or checking the adequacy of design, l and that design changes, including field changes, be subjected to design control ;

measures commensurate with those applied to the original desig !

The team had concerns that seismic bolting spacing problems had not been adequately incorporated into the seismic calculations for DCP #9600148. The seismic calculation only identified that there was only one spacing problem between the bolts. Field change request (FCR) #960062, dated June 7,1996, to !

the DCP, identified that five bolts had spacing problems that required evaluation j to determine if the seismic analysis was still adequate. The licensee stated that the seismic analysis bounded the worst case seismic situations, so that additional seismic evaluations were not necessary. However, the team identified that the seismic analysis was not accurate in that it specifically stated that only one spacing problem existed with this DC (2) 10 CFR Part 50, Appendix B, Criterion XVI states, in part, that measures shall be I established to assure that conditions adverse to quality are promptly identified i and corrected. In the case of significant conditions adverse to quality, the !

measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetitio On February 26,1998, the team conveyed the above seismic bolting concerns to I the licensee with a request for a walkdown to validate the distances between '

bolts. The licensee discovered during the walkdown that the modification had not been field completed. The modification for battery rack #1 AF01EA-B was completed. However, the modification for the battery rack #1 AF01EB-B was not implemented in the field and still contained 16 bolts. The design engineer could '

not explain why the modification had not been completed in the field. In addition, the design engineer stated that there was no requirement for design engineers to Wdikdown completed design changes. The failure to walkdown completed design changes was considered a program weakness. PIF #B1998-00952 was issued on February 27,1998, to evaluate this plant problem.

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r This modification had been originally initiated as a result of a bolt failure on battery rack #1 AF01EA-B during torquing, which was attributed to corrosion. As a precaution the licensee decided to remove all 32 expansion anchors for battery racks 1 AFO1EA-B and 1 AF01EB-B along with the 1/4" plates they were attached to and replace them with new plates and anchors.

l The DCP was signed as complete by the maintenance staff. Following NRC questions, the licensee conducted an investigation of the maintenance staff's decision to not complete this DCP. The DCP did not contain an option to only complete one-half of the DCP. The system engineer stated that he had been j consulted for the cancellation of this modification. Maintenance sta'f's difficulty in performing the first part of modification and the low amount of corrosion on Rack #1 AF01EB-B were the reasons given for permission to cancel the DC .

However, there was no documented evidence of the engineer's evaluation for l making these decision The decision to not complete the DCP allowed a potentially degraded condition i to exist unevaluated since June 7,1996. Battery Rack #1AF01EB-B had not l been removed to evaluate the condition of the bolts and anchors. In addition,

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the failure to complete this DCP resulted in the as-built design drawings and the ,

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seismic calculations to not match the design of the plant for the AF battery rack The licensee stated that the #1 AFO1EB-B Rack would not be modified based on i the design margin of the bolts and anchors. In addition, the as-built drawings and seismic evaluation would be changed to reflect plant conditions. However, I no written evaluation would be performed.

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(3) In a related issue, Byron inspection Report 50-454/455/95011, dated January 29,1996, documented that on December 5,1995, the NRC identified that terminals 8 and 11 on the same AF Pump 1B battery (1 AF01EB-B)

contained rust. This was apparently due to water from a service water valve packing leak over the batteries. The water from this leak also covered the floor by the AF battery rack bolts and anchor c. Conclusions On February 4,1998, the team identified that a field change performed on June 7,1996, i was not subjected to design control measures commensurate with those applied to the original design. In addition, a AF battery rack was not installed as required by DCP l #9600148 resulting in as-built drawings and seismic calculations that did not match the plant design. This is a violation of 10 CFR Part 50, Appendix B, Criterion lli (50-454/455/98004-02(DRS)).

On February 26,1998, the team identified that corrective actions were not prompt for a degraded condition for the bolts and anchors for the AF battery rack. DCP #9600148 1 issued to correct this condition had not been completed since May 15,1996. This is an example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-454/455/98004-03a(DRS)).

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The team concluded that not having a requirement to walkdown completed DCPs contributed to the above failure E1.3 Lack of Indeoendent Verification Process for Exemot Change (modification) installations Insoection Scoce The team assesseli the licensee's corrective action and self assessment process. The team examined the underlying circumstances asrociated with PIF B1997-01549, dated December 29,1997. This PIF documented a wiring discrepancy identified by the .

system engineer in the EDG control cabine j 1 Observations and Findings l PlF B1997-01549, dated December 29,1997, documented a wiring discrepancy identified by the EDG system engineer in EDG panel 1PLO8J (a jumper that should have been removed was left installed in the field). The discrepancy was identified during testing conoucted using special test procedure SPP 97-033. The miswiring could have resulted in the loss of 1B EDG during a fir The team reviewed the associated EDG schematic and wiring diagrams and interviewed the system engineer. During the interview, the team noted that a second wiring discrepancy between the drawings and the field installed EDG wiring was also identified I during testing by the system engineer. A jumper that should have been installed in EDG j panel 1PLO8J was missing in the field. The system engineer promptly issued PlF B1998-00576 on February 4,1998, to document this discrepanc The team determined that the particular wiring discrepancies identified in the PlFs )

occurred in May 1996, during the installation of exempt change (EC) DCP 950018 !

The DCP was initiated as part of Thermo-Leg resolution to meet " Appendix R" safe shutdown requirements. The modification was to resolve inadequate fire separation issue with Normal Supply 2 (PS-2). The control power for each EDG was originally provided by two separate DC feeds; Normal Supply 1 (PS-1) and Normal Supply 2 l (PS-2). During a loss of offsite power (LOOP), the EDG is required to start and run assuming a fire disabled Normal PS-2. The EC DCP 9500185 was designed to repower some critical components from Normal PS-2 to Normal PS-1 so that the EDG could start and run with only Normal PS-1 available. The modification would ensure that fire in Zones 5.4-1 and 11.6-0 would not damage cables of Normal PS-2 power feed of both EDG 1 A and 1B and disable functions which are essential for starting of both EDG 1 A and 1 The team noted that the electrical maintenance technician that installed the field wiring design changes may have made the wiring errors (could have removed tha wrong jumper), and as a result, cross tied the two EDG 125V de control power supplies (PS-1 l

and PS-2) which must be isolated from each other. The licensee corrected the wiring errors using

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work request (WR) 970137338. The same design change was implemented on EDGs 1 A,2A and 28. The licensee inspected the changed wiring on the other three EDGs and found them to conform to the design drawing The 50.59 safety evaluation performed for EC DCP 9500185 stated, in section 5, that the change did not introduce any new failure modes and that repowering connection changes would be done to internal wiring of the panels in a manner similar to existing terminations. It further stated that all components would be available to do their required function; and that all necessary testing would be performed to verify that all critical functions remained unchanged as well as intended changes for design functions

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j as required without any detrimental effect. Furthermore, section 7.c. stated, changes would be tested prior to turnover to operation for intended function and to verify that no other malfunction was created as a result of the wiring changes. Therefore, the safety evaluation conclusions that the probability of the malfunction of safety related equipment was not increased. The team noted that as a result of the miswiring, the statements and assumptions made in the 50.59 safety evaluation were incorrec ,

The team performed a field, cursory sample inspection, of EDG 1 A control panel 1PLO7J using the electrical wiring and schematic diagrams. Several wiring labeling discrepancies were identified; however, the number of wires on the terminal appeared to conform to the number delineated on the wiring drawings. The licensee issued PlF B1998-00606 on February 8,1998, to correct the labeling errors and verify that the field wiring was indeed correc The team also requested that the licensee perform a field wiring inspection of all four EDG local panels to determine if other wiring discrepancies existed due to the lack of independent verification process The licensee inspected the panels (by mostly comparing the number of wires terminated at each terminal) and identified wiring drawings and labeling discrepancies. PlFs B1998-00875 and B1998-00876 were issued on February 20,1998, to address the finding Procedure NSWP-E-02, Exhibit F, dated May 13,1996, was used to implement WR 950047014-01. The inspectors noted that the miswiring of #53 relay contacts M2 and M3 in panel 1 PLO8J was performed by the installer without quality control (OC) overview or other independent verification done. The work instructions for the WR 950047014-01 were written by the licensee using nuclear station work procedure NSWP-E-02,

" Electrical Cable Termination and Inspection," Revision 4. This procedure did not require the use of independent verification of internal wiring changes. In addition, Byron administrative procedure BAP 1099-3, "QC Field Inspections," Revision 3, did not require 100% inspection of safety related exempt change installation The team requested that the licensee generate a PlF and nuclear tracking system (NTS)

items computer list using the keywords " wiring" and " configuration control", The list generated showed that at least 40 PIFs and/or NTS items were issued in 1996 and 1997 to document and track various field wiring deficiencies. The team was concerned that with this large a number

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4 of wiring discrepancies, no root cause analysis or trending analysis was initiated. The

, licensee subsequently initiated PIF B1998-00622 on February 6,1998, to determine if l

an adverse trend regarding wiring discrepancies existed at Byro The EC DCP specified construction modification and operability testing. The i construction testing ECPT #19 required, in part, that operational analysis department (OAD) verify that the revised connections were done per schematics and wiring changes

in the ECN. The modification testing required, in part, simulation of Normal PS-2 loss of l power. The modification testing performed following installation of EC DCP 9500185 l l failed to identify the wiring discrepancies and found EDG 1B fully operabl !

The team closely examined the testing performed following the EC installation. The !

team noted that the licensee had established six barriers for post-modification testing to enswe that installed modifications were tested successfully and that the equipment was l installed as designed / intended. The barriers were: (1) the worker using the " STAR" and

"QW" principles; (2) independent verification; (3) QC overview; (4) construction test !

l ECTP #19 whose purpose was to verify wiring continuity; (5) post-modification testing, l performed to ensure the design intent of the modification was satisfied; and (6) the )

operability testing, typically the TS surveillance. It was apparent to the team that none i of the six established barriers prevented or identified the miswiring error j

The team concluded that the licensee's process for exempt change (modification)

installation was inadequate. Specifically, the team identified that there was no requirement in place to perform independent verifications by electrical maintenance ;

craft, engineering staff or QC in order to verify that all safety-related wiring installations performed via the exempt change process conformed to the requirements of the design ,

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l On the positive side, the team noted that the EDG system engineer was proactive in l contacting the Braidwood EDG system engineer, in initiating the special test to test the untested switches and in identifying the wiring errors.

I ConclusiQns The team concluded that the licensee's process for independent verifications of exempt change (modification) installations was inadequate. Specifically, the team identified that there was no requirement in place to perform independent verifications by QC, electrical maintenance craft or engineering staff in order to verify and ensure that all safety-related wiring installations performed via the exempt change (modification) process conformed to the requirements of the design change document Failure to establish an effective process for independent inspection and verification of modification activities affecting quality such as field installations of safety related exempt changes is considered a violation of 10 CFR Part 50, Appendix B, Criterion X (50-454/455/98004-04(DRS)).

E Review of Exemot Chanaes and Modifications

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. Insoection Scoce The team reviewed selected design modification documents, calculations,50.59 safety evaluations (SEs), and operability assessments. The modification packages were reviewed for technical adequacy, completeness and field implementation including testing and modification closure.

d The team identified a concern which involved licensee failure to ensure that selected field-installed design change modifications had been properly evaluated, tested, signed-off as completed and operable prior to placing them in service. The licensee's process for controlling modifications to ensure adequate post-modification testing and package closure was weak. The licensee provided the team with a completed list of modifications that had been partially or fully installed but not fully tested in the field and in use by operations. The list, which was provided on the exit date, February 10,1998, included numerous active DCPs (not fully completed in field or tested). The team identified several modifications that had been physically installed and placed in service, even though the modification packages were not signed off as completed and authorized for use by operations. The following modifications were reviewed:

(a) DCP 8500999 (M6-0-85-0120)-- This safety related modification was originally installed in 1986. This DCP installed heat tracing on the exposed portions of the essential service water (SX) chemical feed lines to provide cold weather protection for the chemical feed lines so that the chemicals would not crystallize at low temperatures and block the flow. Two chemicals begin to crystallize at approximately 60*F and freeze at about 20*F. These feed lines are used for SX system chemical control including acid for PH control, hypochlorite for microbiological control, and two chemicals used for scale and corrosion inhibitors. The scale inhibitor provides heat exchanger protection and the corrosion inhibitor provides long term corrosion protection of piping and component surfaces. The team reviewed this modification and identified the following concems:

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The licensee could not locate historical data for the period between 1986 and 1994 concerning this modification and past work performed on the chemical feed lines. However, during interviews with system engineers, the team found that between 1988 and 1992 at least seven work requests (WRs) were issued to cut out the four SX chemical injection lines and install new pipe sections because they were found completely clogged (possibly due to crystallization). Root cause was given in the WRs as

" abnormal wear."

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At the time of the inspection, the DCP was open, waiting for completion of testing requirements and package closure. The team determined that although the modification was installed in 1986 and placed in use, the modification testing was approved in 1993 and performed unsuccessfully in 1994. The test was not successful because one of the four thermostats failed to reset. MWR B10072 (WR940011365) was

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t generated on August 1,1994, to correct this deficiency, but was never implemented in the field. Tne WR940011365 documented on November 3,1997, that " heat trace had been repaired by unknown party." The test was re-performed on January 31,1998, following NRC questionin .

As a result of ultimate heat sink design basis reconstitution in 1994, the i SX cooling tower (SXCT) basin level was increased. The licensee issued ECN 000947E, in April 1997, to address the effects of the increased SXCT basin level. The licensee identified that some of the original installed heat tracing and insulation were submerged under water, resulting in degradation of the heat tape and insulation. A decision was made to remove the insulation and relocate the heat trace. In July 1997 the ECN was completed in the field and placed in use, but was not fully teste . Design drawing 6E-0-4030HT09 stated that all four heat trace thermostats for the chemical feed piping to the SX basin should be set to open above 80*F. FCR F-71531, was initiated December 10,1986 to change the thermostats set point from 60*F to 80*F to ensure that the chemicals do not crystallize. The thermostats were recently found to be i set in the field at 60*F. Following NRC inquiry into this issue, the set point change was made (from 60*F to 80*F) in the field on January 31, 1998 (PIF B1998-00500).

(b) DCP-9201399- dated December 16,1992, " Replace modicon with new updated

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hardware / software-current equipment obsolete." WR 940042333-01 replaced the existing Modicon controller with a new controller for the makeup demineralizer (WM)in May 1995. The package was sent to system engineering for operational testing in August 1995. Various discrepancies were identified in 1995 between the Modicon program and the logic drawings. Although the system has been in use by operations, programming problems had not been resolved at the time of the inspection and operations procedures still needed to be revised to reflect new programming changes. Finally, system engineering i needed to perform exempt change close out activities. The team was informed that projected date for completing this BOP modification was March 1998. The team noted that interface problems between engineering, purchasing, vendor and operations resulted in this system operations enhancement modification not being completed.

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(c) DCP 9201089 - dated September 16,1992, was initiated (following an NRC l concern) to add cathodic protection to under-ground H2 gas header OHYO1 l (from HY farm to station). NRC open item 454/92007-01 documented a concern l regarding protection from corrosion of hydrogen gas in under-ground pipes. The l

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inspector was concemed that since the pipe had no cathodic protection, faults and discontinuities in the pipe coating could develop and lead to corrosion of the pipe with a subsequent hydrogen release causing a fire and explosion hazar l l 1

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The licensee determined, in 1992, that the level of cathodic protection provided for the hydrogen piping was unacceptable; it was at .385 volts versus a required acceptable value of .85 volts. The NRC open item was closed based on !

licensee commitment to address this safety concern. During subsequent licensee attempts to address this concern in 1994, a survey showed the pipe as shorted and not receiving any cathodic protection. In addition, the header pipe !

could not be Rcated due to interference from adjacent buried structures. The j team was informed that because of the length of time the old pipe was in the /

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ground unprotected, an action request was written in January 1998 to replace

! the pipe, c. Conclus10ns I The safety related modifications reviewed by the team were generally adequat ,

However, the team was concerned that inadequate attention was placed on balance of I plant but important to safety modifications.

l The team determined that the licensee's failure to take adequate corrective action and ensure that field-installed safety related modification DCP 8500999 (M6-0-85-0120)

had been properly evaluated, tested and signed off as completed prior to placing it in service, is considered an example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-454/455/98004-03c(DRS)).

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E2 Engineering Support of Facilities and Equipment i

E2.1 Out-of-Tolerance Safetv-Related instrumentation /Comoonent Controls l Insoection Scoce The team examined activities to develop an instrument out-of-tolerance (OOT) trending I

program. The team ascertained whether established programs were in place to ensure that OOT instruments were identified, their cause determined and corrective action i l taken to preclude repetition. The review included interviews with appropriate Byron :

Station personnel and review of equipment trending printout '

l l Observation and Findinas The team determined that Byron Station personnel could not provide a listing of safety-related instrumentation that were determined to be OOT for two or more consecutive calibrations over the past five years. The team did receive a more limited j fisting of transmitter trending printout A review of these printouts revealed that there were 37 instances in Unit 1 and 35 instances in Unit 2 where transmitters in safety-related instruments were OOT in two or more consecutive calibrations. Some transmitters were OOT in as many as four consecutive calibration i (

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Further review of this matter revealed that personnel were not aware of the existence of Corporate Procedure NES-EIC-20.03 " Evaluation Of Instrument Performance" dated May 5,1997, therefore, the requirements of this procedure were not being implemented at Byron Station. The procedure stated that if an instrument was consistently founo outside the administrative limit, the probability was high that the instrument was starting to fail. The procedure also stated that in order to make a valid determination of an instruments' degradation, a trend of its performance over time was to be documente The procedure required, in part, that for transmitters found to be two consecutive times OOT, the inspection interval must be decreased; and transmitters found to be three times OOT in three consecutive calibrations were to be considered misused or failed and shall be replaced. The team determined that these corrective actions were not taken for transmitters found in this category, in response to the teams' concerns, licensee staff stated that implementation of the corporate NES procedure was under review and had not yet become policy at Byro PIF B1998-00462 was initiated to address this concern.

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The team determined that the licensee failed to implement an effective program to l address a long standing issue regarding resolution of OOT conditions. A concern relative to OOT instruments was previously identified in NRC inspection report 454/95011. There was a lack of communication between site engineering and corporate nuclear engineering on the method for implementation of the standar Conclusion The team concluded that the licensee failed to implement an effective corrective action i program to evaluate and address repetitive OOT conditions adverse to quality even J

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though the very same issues were raised in previous NRC inspections both at Byron l Station (IR 454/95011) and the Zion Station (IR 295/97023).

The team informed the licensee that failure to assure that conditions adverse to quality are promptly identified and corrected is considered an example of a violation of 10 CFR Part 50, Appendix B, Criterion XVI (50-454/455/98004-03b(DRS)).

E2.2 Electrical Cable Imoedance Discrecancy Insoection Scoce l

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On January 21,1998, Byron Station issued PlF No. B1998-00321, " Cable Impedance Discrepancy." This PIF stated that on January 16,1998, a 10 CFR Part 21 report was initiated at Clinton Station regarding the use of incorrect cable resistance values in determining cable tray loadings and voltage drop of cables rated less than SkV. Sargent and Lundy Standard ESA-102 did not correctly reflect resistance values for tin-coated copper conductors used at Clinton and Byron Station l l

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Observations and Findinos The licensee prepared PlF No. B1998-00321 to acknowledge that Byron Station was -

aware of this problem and to require an operability assessment as prescribed in BSE 10-1, Revision I," Operability Assessment Procedure. Byron Station continued to pursue this issue following BSE 10-1 by completing Attachment B of that procedure '

(LOG No.98-007). Attachment B concluded that the Sargent and Lundy " Evaluation of the Impact of Using STD ESA-102 Cable Impedance Values in Design Calculations,"

dated November 21,1997, concluded that the conservatism in the assumptions and parameters in the voltage drop calculations, when considered jointly, more than l compensate for the errors introduced using the data in ESA-102. Nonetheless, the l i

Byron Station review could continue with completion of BSE 10-1, Attachment C Operability Assessment. The team independently reviewed Sargent and Lundy's

" Evaluation of the impact of Using L D ESA-102 Cable Impedance Values in Design ,

Calculations," dated November 21,1997, and Byron Station Operability Assessment, )

BSE 10-1, Attachment B, and agreed with their conclusion '

The team's evaluation of the licensee's actions considered that the resolution of this issue was very good. However, a weakness was identified in that BSE 10-1, Attachment C, had no firm completion date. The team observed that the marginal cases should be bounded and resolved on an expedited schedul The licensee provided the E&TS Team Leader, during the Exit Meeting held on February 10,1998, with a copy of the Action Plan titled "ESA-102 Cable Impedance Change Impact Assessment for Byron and Braidwood Stations. The action plan included assessment of impact of cable impedance change on several of marginally acceptable circuits and on voltage drop and ampacity calculations. This plan scheduled the final actions to be completed by April 15,199 I Conclusion The team concluded the licensee acted promptly and in accordance with the procedures established to resolve operability issues. This item is considered Unresolved pending ;

licensee completion of the action plan to assess impact of cable impedance change on I

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marginally acceptable circuits and further NRC follow up (50-454/455/98004-05(DRS)).

E2.3 Assessment of Switchvard l E2.3.1 Walkdown of the Switchvard Insoection Scoce As par 1 of evaluation of the SY (switchyard) system, the inspectors walked down the switchyard and the switchyard control room to assess the material condition of the equipment. The team observed the material condition of the switchyard batteries and control cubicles in the switchyard control roo . l n

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The material condition of the equipment in the switchyard control room was generally good. The team also walked down the switchyard. The team noticed that some relays ,

in the cabinet of Air Circuit Breaker ACB 6-7 were hanging in the form of an arc with the relay mounting plastic bracket melted by the heat generated by the cabinet heater. PIF g No. B1997-03248 was issued by the licensee on September 19,1997, regarding the poor condition of this ACB cabinet. This PlF stated, in part, that nearly all components in the cabinet capable of rusting were rusted and the condition was totally unacceptable by station standards. Failure of these breakers could result in a loss of offsite power. In addition, the shift supervisor noted on this PlF that the breaker condition was most likely the result of an inadequate preventive maintenance progra The licensee's switchyard supervisor stated that these relays were operational at l present. Even though this breaker was classified non-safety related, the team

, determined that more attention should have been paid to the maintenance of these

) relays, in view of the importance of the switchyard breakers, as loss of offsite power was l the most important contributor to the core damage frequency.

I Conclusion The team concluded that the switchyard and the switchyard control room were well l maintained except for the relay mounts in the breaker cabinets. The team was I concerned that the true root cause for the sagging relays has not been determined.

l E2.3.2 SMtchyard Breaker Maintenance Insoection Scoce The team reviewed the licensee's maintenance of the breakers in the switchyar Observations and Findinas

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Te SY wJem was initially placed in the a(2) category under the maintenance rule and was placed in a(1) category in January 1998, as a result of exceeding performance l criteria for switchyard breakers. There were three relief valve failures during 1997 and l two in January 1998 on the air blast circuit breakers, as indicated by the station PIF The vendor (Brown-Boveri) maintenance manual (CH-A-109116E) for the type DLFK air circuit breakers recommended maintenance be done on several components, including l

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safety (relief) valves once every 10 years. However, the licensee had not implemented this vendor recommendation, even though these breakers were much older than 10 year The licensee started to replace these relief valves during 1997, due to a requirement by the State of Illinois to test these valves. As a result of the licensee not installing these valves correctly, the valves were unscrewing from their air tank fixtures when these valves relieved pressure. The licensee did not adequately identify the root cause for

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these initial failures. The licensee attempted to correct the problem by increasing the l length of the mounting nipple. This did not correct the problem and the valves continued l to fail until January 1998. The licensee was still investigating the root cause at the conclusion of this inspection. The inspectors noted that the switchyard should have I been placed in the a(1) maintenance rule category during 1997. This was not done because the SY system engineer did not classify a relief valve failure as a farctional failure during 1997. This was identified by the licensee and a PIF was issue Conclusion The team concluded that increased attention was needed to improve maintenance of the switchyard breakers that failed. The switchyard maintenance was considered a weakness.

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E Design Engineering Caoability Insoection Scoce The team examined the mechanical technical staff capabilitie Observations and Findings The mechanical engineers, directly involved with the team in the discussions of technical issues, were found to be qualified and experienced in their respective position Further, engineers demonstrated pride and ownership of their respective areas of responsibilities, Conclusion The team concluded that mechanical design engineering capability was generally very good at the Byron Statio E2.5 Auxiliarv Feed System Flow Issues Insoection Scoce The team conducted an assessment of the status of several auxiliary feed system suction pressure and flow issues and related system modifications. The related design and operability issues had been documented in licensee's * Auxiliary Feed Design Basis Review Team Report," dated December 30,1996. The team reviewed the design issues, changes and the related document Qbservations and Findings The report included issues relative to the adequacy of documentation of system flow capabilities for various accident analyses. The auxiliary feed pump suction trip set points were also determined by the licensee to be non-conservative for some design

t basis events. The report left open issues on design flow limiting orifices and the final resolution of the continuing problems related to suction pressure transients. There was an additional issue regarding updating the updated final safety analysis report (UFSAR)

to reflect set point change The team determined that the auxiliary feed system modifications, operational adjustments, and related calculations were adequate to address identified issues and flow problem The team noted minor descriptive discrepancies between PSA-B-97-13 and -14 regarding the location at which pump suction pressure was measured (2 feet vs. 3 feet

"above the pump suction on the six inch pipe"), but no significant concerns were identified. The licensee issued a PlF to correct this discrepanc Conclusion The team concluded that the auxiliary feed system modifications, operational adjustments, and related calculations were adequate to address licensee's identified issues and flow problem E3 Engineerina Procedures and DocumentatIQD E31 Plant Modification Administration Insoection Scopa The team reviewed corporate engineering guidance and plant-specific procedures and documentation. In particular, the team reviewed engineering administration procedures related to plant modifications. This team considered the quality of these procedures rather than the effectiveness of their implementatio ,

b. Observations and Findinas In general, the corporate and plant-specific guidance was evaluated as being very good in content, providing a sound basis for good plant performance in the area of engineering modifications. For example, NEP-04-05, Revision 0, issued January 1995, titled " Design Change Acceptance Criteria," provided concise administrative and technical guidance. Checklists were included for the different technical disciplines and for cross-discipline considerations. Key questions were provided that guide engineers in the development of testing requirements, including construction tests, modification-specific tests, and final operational test The team found a potential weak area in NEP-04-01, Revision 4, dated March 28,199 Section 4.6.6 of that procedure allowed the replacement of some safety related parts and components with non-exact items with only a " technical evaluation." While the j items listed (e.g., gaskets, packing, grease, bolting material, and bearings) were not I necessarily critical to ensuring nuclear safety, this section of the procedure could cause l

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I potential equipment reliability problems. Careful monitoring of such technical evaluations and assessment of emergent plant problems relative to this less formal process may be neede Conclusion Engineering procedures and documentation were assessed by the team to be very good. The team considered Section 4.6.6 of NEP-04-01 to be a potential source of concern since it appears to encourage a range of non-exact item replacement E3.2 Epilure to Uodate UFSAR Section 6.5.1.2.3.1 on Fuel Handlino Buildino Exhaust System Analvsis Results Insoection Scoce The team reviewed information related to UFSAR Section 6.5.1.2.3.i for the Auxiliary Building Ventilatio Observations and Findings UFSAR section 6.5.1.2.3.i included inconsistent data on temperatures with and without heaters (Case ill and Case IV). The inconsistency was a result of incomplete

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information in the UFSAR on initial conditions. While reviewing the related UFSAR information, the licensee discovered that the data had also not been updated to conform to a 1986 calculation. To address this discrepancy, the licensee issued PIF B1998-00354, "VA calculation revision results not updated in the UFSAR Section 6.5." l Conclusions 4 The team noted that inconsistent or incomplete information for the VA system design existed in the UFSAR since at least 1986.

, E4 Engineering Staff Knowledge and Performance E System Engineering Assessment and Activities Insoection Scooe The team interviewed selected system engineers and engineering supervisors. The team reviewed selected system notebooks. The team walked down the switchyard with the system engineer ) Observations and Findings

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The team interviewed the system engineers assigned to the switchyard (SY) and the auxiliary feedwater (AF) systems. The system engineer for the SY system had one year i of experience as a system engineer. The system engineer for the AF system had been

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a system engineer for seven months. The system engineers interviewed appeared to be knowledgeable of their systems and of the problems in their system The team reviewed the system notebooks for the SY, Auxiliary Power (AP) and AF systems. These system notebooks contained system descriptions, UFSAR sections, industry contacts and description c.,f events on the respective systems. The team did not identify problems with the system notebooks reviewed. The team noted that the Byron system engineering handbook stated in section 3.1 that the system manager (system engineer) is responsible for "being knowledgeable of significant contributors to the plant's core damage frequency based on PRA for operating and shut down conditions."

However, neither the system engineer (SY and AP systems), nor his group leader were aware that the loss of offsite power was the most significant contributor to the core damage frequenc l During the last engineering inspection at Byron in December 1995, the NRC identified 1 that detailed guidance and expectations were lacking for system engineers on how to conduct system walkdowns to identify equipment deficiencies. During this inspection, 3 no conceins were identified in this are Conclusion l

The system engineers interviewed appeared to be qualified for their jobs. Their experience on the job as a system engineer was low (less than one year) for two of the system engineers interviewed. The engineer's.PRA knowledge appeared to be minima However, the system engineers were knowledgeable of their assigned systems. The team did not identify any problems with the system notebooks reviewe E4.2 Mechanical Enaineers Technical Knowledae Insoection Scoce I i

The team selected and evaluated several mechanical modification packages and ;

calculations in detail and several of the responsible engineers were interviewed.

l Observations and Findinas The Byron Station mechanical engineers interviewed during this inspection were i knowledgeable of their technical products. The team assessed the engineering technical products as appropriately detailed for the issues being addressed. The better engineering products were often more recent documents produced during the past few

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years as compared with those calculations that were several years old.

l All of the Byron Station engineers interviewed were assessed as having a positive l attitude toward their work and, thus, contributing to a good nuclear safety culture. They l

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were assessed as being highly motivated and professional. Moreover, the team noted that Byron engineers communicate readily within their organization and with thei . corporate counterparts for mutual suppor Conclusion The team concluded that Byron Station's mechanical engineering products and staff were generally very good, largely as a result of their positive attitude toward their work, good communications with each other and interfacing organizations, and a high level of

mutual support.

I E7 Quality Assurance in Engineering Activities E Quality Assurance Audits /Surveillances and Engineerina Assessments j Insoection Scone The team reviewed several Site Quality Verification (SQV) audits /surveillances, l Engineering Assurance Group (EAG) assessments and other external assessments, for l their scope, depth of and quality of audits and the licensee's follow up of corrective j actions for the items identifie ; Observations and Findings The team reviewed the following SQV audits / surveillance in the engineering areas:

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. QAA-06-97-08 Design Control l . QAA-06-97-10 Corrective Action

. QAS-06-96-002 System Engineering Department (SED) System / program Notebooks

. QAS-06-96-022 Electrical breaker Refurbishment '

. QAS-06-96-027 Configuration Management Review

. QAS-06-97-029 CC System design basis conformanco review The quality of these audits /surveillances was generally good. The team reviewed t selected audit / surveillance findings for verification of licensee's follow up. These items 4 I

were tracked adequately for satisfactory completion of corrective actions. In addition, the team determined that field monitoring reports were' excellent assessments of plant activities. Quality verification surveillances and audits were thorough and detailed with

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significant findings identifie An example of a good external audit was the I&C assessment performed in May 199 This audit contained some very good findings. The plant response was provided in June 1997; however, the licensee had yet to generate the NTS items to follow up on the findings of this assessmen #

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Some assessments by external auditors contained good findings. An external design control assessment between May 1997 and September 97 was considered very goo Findings identified in this report were followed up as NTS ltems. However, findings in the following areas were not being followed up: Operator work arounds; problems with system notebooks; lack of questioning attitude; lack of proper standards; and Westinghouse calculation retrievabilit During the last engineering inspection at Byron in December 1995, the NRC identified design calculation errors which were not identified during the licensee's design review l process and a violation was issued. The licensee identified some category 5 and l category 4 items relative to calculations in the November 1997 EAG report. However,

the team noted that follow up activities were narrowly focussed and that the number of calculations reviewed by the EAG in December was not increase The team also identified that there was a weakness in the timeliness of the implementation of Maintenance IPAP Recommendations. The IPAP report was issued more than a year ago with only 20% of the recommendations complete Conclusion

The audits / assessments conducted by SQV and outside auditors were done well and l included several significant findings. The licensee, generally, followed up the audit / assessment findings adequately; however, some weaknesses in follow up of identified issues were noted.

l l E7.2 Self Assessments bv Enaineerina Decartments l

Insoection Scoce

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The team reviewed engineering activities regarding effectiveness in identifying, resolving and preventing problems. The team reviewed several self assessments conducted by system engineering and other engineering departments. Additionally, the team l evaluated the licensee's process for initial identification and characterization of the

! specific problems, elevation of the problems to proper levels of management for i resolution, disposition of any operability /reportability issues and implementation of corrective actions, including evaluation of repetitive condition i Observations and Findinas The self assessments by system engineering were satisfactory; however, the self assessments by the design engineering departments needed improvement. No guidelines were provided for performing self assessments in design engineering and the )

assessments reviewed were not uniform or well structured. The self assessment files !

did not include corrective actions taken to correct any problems identified or the dates j when corrective actions were proposed or completed. The corrective actions for some assessments were shown as closed in the assessment log; but the corrective actions

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were not yet completed, and the self assessments book was not in proper order. One electrical self assessment was not found in the boo '

The team noted that the guidelines provided for system engineering self assessments stated that findings as a result of spot assessments (such as review of system notebooks, or certification guides for engineers) need not be documented. After the team pointed out that these reviews were important, particularly in view of some adverse comments by an external auditor on the inadequacy of system notebooks, the system engineering supervisor promptly revised these guidelines, to include the requirement of i documentation of deficiencies, if discovere l The licensee informed the team that a corporate procedure was being developed for self I assessments in engineering. This procedure was expected to provide better guidance I in performing these self assessments. The procedure was to be issued in February 1998, i Conclusion Self assessments conducted by system engineering were effective, however, those conducted by design engineering need improvement. More guidance was needed for i follow up on the findings identified during these self assessments. The implementation of self assessment in Engineering was considered a weakness. The licensee was taking action to resolve these concern E8 Miscellaneous Engineering Issues E8.1 Reactor Plant Shutdown and Cooldown without Pressurizer Heaters I Insoection Scoce During this engineering assessment, the team determined that the licensee had not protected pressurizer heaters from fire damage under 10 CFR 50, Appendix Appendix R requires that the licensee must be able to safely shutdown and cooldown the reactor after a fire. The team examined this issu Observations and Findings The team reviewed procedures and supporting documents related to safe shutdown and cooldown. The licensee provided several normal and emergency operating procedures that relied on the availability of pressurizer heaters, but no supporting documents that addressed operations without pressurizer heaters were provide The team focused their review on the licensee's methods of reactor coolant system pressure control to determine how shutdown and cooldown with no pressurizer heaters available would be achieved. As a result of inquiries by the team, the licensee conducted a shutdown and cooldown evolution on their simulator and discussed the results with the team. The team also interviewed an experienced operator and went

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l through the applicable procedures with him, assessing how the operators would implement the procedures.

Based on these inquiries, the team determined that no engineering studies or computer codes discussed with or provided to the team during this inspection specifically address the most appropriate methods for pressure control during shutdown and cooldown l without pressurizer heaters. Likewise, the team determined that the simulator most likely does not provide sufficient modeling in this are Moreover, plant procedures (e.g.,1BGP 100-5, precautions in section D.2, PRESSURIZER) direct the operators to use backup pressurizer heaters under certain conditions "to avoid a temperature stratification within the pressurizer that could lead to a cooldown transient in excess of Tech Spec or Administrative limits." In spite of such precautions, the Byron Station procedures for shutdown and cooldown did not specifically mention or address the potentially more severe situation in which operators might have to cooldown the reactor plant with some or all of the pressurizer heaters not being available. The procedures provided to the team assumed that the pressurizer heaters were always availabl The licensee stated that, if current procedures were used for shutdown and cooldown under the conditions suggested by 10 CFR 50, Appendix R, that the operators would have to initiate safety injection. This would likely be followed by safety injection termination at least once before achieving solid plant pressure control. The team noted that the safety injection procedure focused on pressurizer level control rather than on pressure control. The team was concerned that without a specific pressure-related analysis, the intermittent use of safety injection could result in potentially unreviewed 1 consequences for reactor plant pressure. Moreover, the team noted that spray bypass I flow would result in gradual depressurization of the reactor coolant system, making some kind of pressure-increasing capability necessary for the operators to control pressure during plant cooldow Based on information provided to the team, none of these conditions or consequences have been addressed for the Byron Station or the Braidwood Station. Nevertheless, this apparent analysis deficiency is mitigated by the presence of systems and procedures that could reasonably be expected to protect against significant core damage even if pressurizer heaters were not available and if subcooling was lost for a brief period of tim c. Conclusion The team concluded that the Byron Station cooldown procedures have not been assessed adequately to address the situation in which the pressurizer heaters are not i

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available, including the fire protection safe shutdown and cooldown situation anticipated by 10 CFR 50, Appendix R. Moreover, the team concluded that the pressure-related consequences of using safety injection intermittently to raise pressurizer level have not i been the subject of engineering studies or calculations to date, either for normal or j emergency operations.

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This item is considered an Unresolved item pending NRC follow up and completion of the licensee's stated commitment to find or develop appropriate technical evaluations and, where applicable, to revise operating and emergency procedures accordingl (50-454/455/98004-06(DRS))

l E8.2 50.54(f) Items Insoection Scong The team attempted to review licensee actions to address 10 CFR 50.54(f) items at Byro ,

l Observations and Findinas The licensee could not easily provide the 10 CFR 50.54(f)information requested since the items were managed by the corporate organization. By the time the licensee provided the packages for review, the team had no time to review the 50.54(f) item I l Conclusion l l

With regard to 10 CFR 50.54(f) items, the team noted that the licensee could not easily retrieve the information requested. The team concluded that this matter required increased licensee attentio E8.3 Assignments of Nuclear Tracking items (NTS) Items to Engineering for Resolution Insoection Scope The team was informed that engineers were reluctant to accept Nuclear Tracking Items (NTS) items provided by root cause investigators for corrective action and follow up of eng;neering issues. The team followed up on this concer Observations and Findings During NRC interviews, the team was informed that root cause investigators have had difficulty getting engineering to accept NTS items and take responsibility for resolving issues associated with investigation findings documented in root cause reports. These reports included NTS items for corrective actions assigned to engineering. The team raised this issue with engineering management and reviewed selected PlFs and procedure requirements. Procedure NSWP-A-15, R1," Comed Nuclear Division integrated Reporting program" Section 6.10.4.1 stated that PORC or CARB management comrnittee members shall be accountable for assigning adequate station resources to ensure that corrective actions are completed within established due date Subsequently, on February 5,1998 engineering management conducted a meeting to address corrective action program issues and initiated various action items to ensure

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that NSWP procedure requirements for adequate resources and priority are assigned to address the NTS item concern. The team reviewed the action items and discussed the proposed actions to address this concern. No additional concerns were identifie Conclusion The team was informed that root cause investigators have had difficulty getting engineering to accept NTS items and take responsibility for resolving issues. The licensee initiated several action items to address this issu E Review of Previousiv identified Unresolved and Ooen Items (Closed) Violation (50-454/455/95009-04(DRS)): This violation concerned blocking open fire doors without a plant barrier irnpairment permit (PBI). Personnel involved were counseled to management's expectations regarding procedural adherence. The licensee ensured that the requirements were strictly complied with. No additional problems were noted concerning this problem. This item is close (Closed) Insoector Follow-uo item (50-454/455/95011-04(DRS)): This item concerned localized pitting and corrosion on a circulating water (CW) pipe, the normal make up line to the SX cooling tower. Arc strikes were repaired under Work Request (WR)

960096520. All major piping valve bodies were surface prepped and coated. The carbon steel riser piping between the riser isolation valves and existing stainless steel distribution headers is being replaced with stainless steel under DCP 9303506. The section of the C Bypass Line that passes through the D Riser Valve will be replaced under WR 970028376. This item is close (Closed) Violation (50-454/455-95011-05(DRS)): The team reviewed information on improvements that were made in the Byron Station calculation management process to improve quality. Calculation issues were raised during a previous engineering assessment, NRC Integrated Inspection Report 50-454/455-95011. The licensee's response to the NRC was in Byron letter 96-0057, dated February 28,1996. Actions taken included corrections to specific calculations, general upgrades in calculation related training and calculation review methods, and in engineer access to design information. Severalimprovements were made to procedure NEP-12-02," Preparation, Review and Approval of Calculations." Procedure NEP-12-02BY," Byron Calculation Site Appendix" has also been upgraded. An additional procedure was planned for implementation during 1998. In addition, the Engineering Assurance Group was formed in February 1997 to improve calculation oversight. Guidance for oversight reviews was included in NES-G-03, " Independent Calculation Overview Review," which has been upgraded to provide better feedback to the plant engineering staff. These corrective actions were assessed as adequate to address this issue. This item is close (Closed) Violation (50-454/455-96009-04(DRS)): The team reviewed the licensee's corrective actions for the failure to have adequate design control measures in place to ensure that the design basis of the Essential Service Water (SX) System was correctly translated into specifications and other plant documentation. As stated in Byron letter

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97-0132, June 13,1997, corrective actions taken by the licensee included revising and applying ultimate heat sink (UHS) calculations to accommodate the potential operability impacts of silt accumulation and an anti-vortex box in the service water cooling tower basin. Based en these revised UHS calculations, the licensee has submitted to the NRC a Technical Specification change request. The licensee also committed to improve administrative reviews of new work items and work backlogs and to upgrade expectations regarding surveillances and design basis knowledge. These corrective actions are essentially completed. This item is close (Closed) Violation (454/455-96012-06(DRS)): The NRC identified that from December 29,1996, through December 31,1996, a change in the facility as described in the Updated Safety Analysis Report was made without conducting a written safety evaluation. The licensee's corrective actions included: (a) a 50.59 safety evaluation was completed on procedure 1 BOS RF-1 on January 16,1997, and (b) an UFSAR update was submitted on October 1,1997. This update included a statement that in addition to the main control room alarm, the station procedures provide for alternate monitoring in circumstances where the alarm function on the containment sump is annunciated due to non-RCS sources. The team verified that a 50.59 evaluation was completed on January 16,1997, and that a change to UFSAR was submitted on October 1,1997. This violation is considered close (Closed) Violation (50-454/455-97015-04(DRS)): This violation involved failure to take timely action to submit a license amendment request to reflect changes made to CST water levels in 1994. The team reviewed Byron letter 97-0315, " Application for Amendment to Appendix A, Technical Specifications, to Facility Operating License,"

dated December 30,1997. The team considered the Byron letter to be responsive to the stated violation and related technicalissues. This item is close F3 Fire Protection Procedures and Documentation F Pre-Fire Plan Uodate Insoection Scoce The team evaluated Byron's pre-fire plan program and implementatio Observations and Findings The team identified on February 5,1998, that the pre-fire plan drawings had not been updated. Changes in the plant design had not been incorporated into the pre-fire plan drawings. The licensee had updated the written portion of the pre-fire plans in 1997 and closed NTS Item #454-315-97-004F-01 associated with this update. However, no PIF had been written to identify that the drawings required an update. In addition, Byron had no process to identify plant modifications that could effect the pre-fire plans, so that these changes could be tracked and incorporated into the drawing Technical Specification 6.8.1 required that written procedures shall be established,

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implemented, and maintained covering activities referenced in Fire Protection Program implementatio BAP 1100-17, Revision 2, " Implementing Procedure For The Pre-Fire Plans," stated, the Pre-Fire plans as written are required by, and meet the criteria of 10 CFR Part 50 Appendix R and the commitments of branch technical position CMEB 9.5-1 Appendix In addition, the procedure required that Fire Marshal and Fire Protection Engineer perform an annual review of the pre-fire plans and sign and date a new pre-fire plan annual cover shee Following the teams identification of these problems, the licensee documented on PlF

1. B1998-00618 that the annual review sheet had not been signed and attached to the pre-fire plans. The licensee stated that they were unaware of this procedural requirement for the past 9 year Conclusions Prior to February 5,1998, the requirements of BAP 1100-17 were not implemented in that a new annual review sheet was not signed and dated for the pre-fire plans and the pre-fire plans were not maintained to meet the criteria of 10 CFR Part 50, Appendix R, and the commitments of NRC branch technical position CMEB 9.5-1, Appendix A, in that the drawings had not been updated for more than 10 years. This was considered a violation of Byron Station's Technical Specification 6.8.1 which required that written procedures shall be established, implemented, and maintained covering activities for fire protection program implementation (50-454/455/98004-07(DRS)) .

F5 Fire Protection Staff Training and Qualification F Eite Brigade Oualifications ingpstion Scoce he team reviewed fire brigade qualification Findings and Observations The team identified that no immediate corrective actions were taken for concerns regarding fire brigade qualifications. Four PlFs (PlF B1997-04081, November 12.1997, PlF B1997-04579, December 12,1997. PlF B1998-0011, January 2,1998, and PIF B1998-0098, January 8,1998) were issued with concerns that the fire brigade members were not qualified. These PlFs were closed without addressing whether the fire brigade was currently qualified. The licensee stated that they were waiting for the medical van to visit the site in February and that the personnel would be medically certified following a complete physicalincluding a treadmill test. The failure to address the problems identified in the PlFs was a program weaknes The licensee's medical department had only recently required the complete physical

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exam for fire brigade personnel qualifications. Previously, the fire brigade members had to only pass respiratory certification and pass the annual fire brigade training to be qualified. The annual training was considered the verification that the person could perform strenuous activities. The licensee claimed that these two activities met the annual physical exam requirement. In addition, during this time, the licensee did not have a formal process to verify that site personnel had passed the medical qualifications and were qualified to be fire brigade members. As a result, medical conditions that would disqualify individuals from the fire brigade were not sent to individuals responsible for updating the fire brigade lis The medical van was on site the week of February 2-6,1998, to give medical exams to site personnel. Part of the fire brigade refused to take the treadmill test, because negotiations between licensee's management and Union officials had not been finalized for treadmill testing. The licensee disqualified these individuals from the fire brigad Following the inspection, on February 9,1998, the licensee issued CAR 06-98-008. The CAR stated: On February 6,1998, during S&QA Audit QAA CE-98-01, " Fire Protection," Q&SA identified two Station Fire Chiefs that do not have current fire brigade qualifications. The CAR stated: The Station does not effectively ensure required fire brigade training is completed and does not effectively ensure the qualifications of fire brigade members. A Radwaste Supervisor did not receive or make-up first quarter 1997 fire brigade training, as required by BAP 1100-1," Fire Brigade Program," step C. PlF B1998-0098 discussed unqualified fire brigade members prior to the Fire Protection Audit. At the time of the audit, Radwaste Supervisors did not have current medical qualifications as required by Procedure BAP 1100-1, step C.9.a. The CAR also stated:

The Station missed the opportunity to identify and correct fire brigade qualifications after PlF B1998-0098 was writte Byron Station Operating License, Section 2.F, requires in part, that the licensee shall implernent and maintain in effect all provisions of the approved fire protection program as described in the UFSAR for the facilit In a letter to the NRC on August 31,1981, Byron committed to the following in the Fire Protection Report: The annual physical will demonstrate that fire brigade members are capable of performing unrestricted physical activitie BP 9.5.1 NRC requirement: "The qualification of fire brigade members shallinclude an annual physical examination to determine their ability to perform strenuous fire fighting activities."

The Byron Fire Protection Report, considered a part of the UFSAR, Section 5.b, required, that the fire brigade members have an annual physical which shows them capable of unrestricted activit , ,'

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. Conclusions The licensee failed to take corrective actions for identified problems with fire brigade qualifications. In addition, the tracking of individual qualifications was poor. Also, the team identified that until February 2,1998, the fire brigade members did not have an annual physical whose results were used to assess their qualifications for unrestricted activity on the fire brigade. The failure to conduct the required annual physical exams was a violation of Byron Station's Operating License, Section 2.F which required that provisions of the approved fire protection program as described in the UFSAR to be conducted (50-454/455/98004-08(DRS)).

V. Manaaement Meetinas X1 Exit Meeting Summary The inspection results were presented to members of licensee management at the exit meetings on February 10,1998. The licensee acknowledged the findings presented. In addition, a telephone conference was conducted with the licensee on March 5,1998, to discuss newly identified technicalissue I

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l PARTIAL LIST OF PERSONS CONTACTED

l Licensee B. Branson, Q&SA, ISEG Supervisor B. Carr, E&TS Inspection Database Coordinator

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B. Cascarano, Supervising Engineer, NES l R. Colgiazier, NRC Coordinator l P. Donavin, Engineering Design Supervisor  !

l T. Gierich, OPS Manager i

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I B. Jacobs, Electrical MOD P. Johnson, Engineering Support K. Kofron, Station Manager B. Kouba, Engineering Manager

! B. Long, IM Support R. Mancini, Electrical Lead K. Passmore, Engineering Program Supervisor D. Popkins, Ex. Admin. Operations Engineer B. Renhart, Chief Engineer, NES B. Wagner, SED Program Manager NflC Z. Falevits, Reactor Inspector N. Hilton, Resident inspector

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I t INSPECTION PROCEDURES USED l IP 37550 Engineering ,

lP 37700

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l Modifications l IP 40500 Effectiveness of Identifying and Resolving Technical Issues l

ITEMS OPENED, CLOSED AND DISCUSSED

l Ooened 50-454/455/98004-01(DRS) URI GL 96-01 - Testing of S.R. contacts 50-454/455/98004-02(DRS) VIO Inadequate design control measures for an AF Modification 50-454/455/98004-03a(DRS) VIO DCP 9600148 had not been completed since May 1996 i 50-454/455/98004-03b(DRS) VIO Failure to implement an effective program to resolve long standing OOT issues 50-454/455/98004-03c(DRS) VIO Modifications in use but not fully tested nor closed out 50-454/455/98004-04(DRS) VIO Failure to establish an adequate independent verification process for Exempt Changes 50-454/455/98004-05(DRS) URI Electrical cable impedance discrepancy (10 CFR, Part 21)

50-454/455/98004-06(DRS) URI Plant Shutdown and cooldown without pressurizer heater available 50-454/455/98004-07(DRS) VIO Failure to Update Pre-Fire Plans 50-454/455/98004-08(DRS) VIO Fire Brigade Not Qualified Closed 50-454/455/95009-04(DRS) VIO PBI Not issued for impaired Doors 50-454/455/95011-04(DRS) IFl CW Piping Corrosion l

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50-454/455/95011-05(DRS) VIO Calculation deficiencies

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50-454/455/96009-04(DRS) VIO Failure to have adequate design control measures for SX system 50-454/455/96012-06(DRS) VIO Failure to perform a 50.59 SE 50-454/455/97015-04(DRS) VIO Failure to submit a license amendment request in a timely manne .

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LIST OF ACRONYMS USED i

BAP Byron Administrative Procedure BTP Branch Technical Position CAR Corrective Action Report  !

CARB Corrective Action Review Board CW Circulating Water CECO Commonwealth Edison Company DBA Design Basis Accident DCP Design Change Package EC Exempt Change ECCS Emergency Core Cooling System EDG Emergency Diesel Generator EQ Environmental Qualification ESF Engineered Safety Feature E&TS Engineering and Technical Support FMRs Field Monitoring Reports FSAR Final Safety Analysis Report HELB High Energy Line Break IFl Inspector Foi!cw up item IP Inspection Procedure LER Licensee Event Report LOCA Loss of Coolant Accident LOOP Logs of 0mce Power NRC Nuclear Regulatory Commission NTS Nuclear Tracking System OOT Out of Tolerance PBI Plant Barrier impairment PlF Problem identification Form QAA Quality Assurance Audit QC Quality Control Q&SA Quality and Safety Assessment SE Safety Evaluation SQV Safety and Quality Verification SSC Structures, Systems, and Components TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved item VIO Violation WR Work Request EAG Engineering Assurance Group

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Partial List of Documents Reviewed Byron Fire Protection Report, Amendment 13, December 1990 PlF #B1997-04081," Fire Brigade Chief's Qualifications" PlF #B1997-04579,"PIF Question Not Answered" PlF #B1998-00011 "First Two PlFs Do Not Answer the Question" PIF #81998-00098," Unclear Fire Brigade and Hazmat Responder Qualifications" PlF #B1998-00618," Pre-Fire Plan Annual Review" Byron Station Pre-Fire Plans, Revision 1 10 CFR 50.59 Screening Evaluation T3-96-0075 DCP #9600148," Mounting Details A Diesel Battery Racks" Calculation #7.16.10.2, " Battery Rack Supports" Letter," Byron Station Units 1 and 2 Fire Protection," August 31,1981 Safety Evaluation Report, February 1982 SWP-A-15 " Comed Nuclear Division integrated Reporting Program," Revision 1 CAR 06-98-008," Fire Brigade Procedure Adherence" Comed Overview of the Medical Evaluation Process / Medical Assessment of the Structural Fire Brigade BAP 1100-17," Implementing Procedure for the Pre-Fire Plans," Revision 2 DCN 9700473, ECN BYR-001015M, " Installation of shaft seal and new type of bearing sealin l l

order to reduce oil leakage in the Aux. Building HVAC exhaust fans," Revision 0, approved !

September 5,1997 DCP 8701382, " Resolve AFW suction Standpipe Overflow Problem" DCP 9400043, PIF B1997-05059," Installation of HEPA Filters without Technical Evaluation,"

dated December 22,1997 DCP 9600228," Install Vibration Monitoring Equipment on the VA Supply and Exhaust Fans,"

exempt change documentation and drawings DCP 9600404/5, Install AF Pump Diesel Drip Pans, exempt change documents dated December 11.1997 DCP 9700400, "B AF Pump Engine Fuel Shutoff Solenoid," Technical Evaluation 97-170, i Revision 0, approved July 31,1997 DCP 9700426, " Valve handle Replacement," Technical Evaluation 97-182, Revision 0, approved, December 11,1997  ;

DCP 9700473, " Replace VA Bearing Seals with Ones that Have O' Rings" l DIT-BB-EXT-0135 (S&L letter CAN-272 of March 3,1992) providing design information on AF pump suction piping standpipe and loop seal modification M6-1/2-87-168; calculations AF-081, AF-082, and AF-91; ECN 06-00227M and ECN 06-00222S; ECN 06-00259 EMD-034501, Addendum M, " Qualify a vent line detail to be added to subsystem 1 AF03 between the 1 AF017A/B and 1 AF006A/B valves," Revision 0, approved May 31,1996 NED-M-MSD-9, Byron Ultimate heat Sink Cooling Tower Basin Temperature: Part IV,"

Revision 4, approved March 17,1997 NED-M-MSD-11, " Byron Ultimate Heat Sink Cooling Tower Basin Temperature Calculation:

Part V, Bypass Operation," Revision 0, approved December 17,1991 l NED-M-MSD-14, " Ultimate Heat Sink Cooling Tower Basin Makeup Calculation," Revision 4, l approved November 5,1997

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SR 97-092," Operability Assessment #97 035: AF/CO/FP Interface," approved July 9,1997; including calculations on seismic and HELB issues raised with regard to AF diesel pump air intakes l PSA-B-95-06," Byron /Braidwood Maximum AFW Flow for Revised SGTR Analysis," Revision 0,

dated April 6,1995 I

PSA-B-96-05," Analysis of AFW Pump Suction Transients for Byron and Braidwood Stations Using RELAPM3," dated June 30,1997 l

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PSA-B-97-10 " Byron /Braidwood AFW Flow Orifice Verification," Revision 2, dated September 3,1997 l PSA-B-97-13, " Evaluation of CST Vortices for Byron and Braidwood Stations," dated

! December 17,1997 l PSA-B-97-14, " Evaluation of New CST TS Levels for Byron and Braidwood Stations,"

I Revision 0, dated December 17,1997

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PSA-B-97-18, * Byron /Braidwood AFW Flow for AF005A-H Modification," Revision 2, dated December 5,1997 PSAG-138,"Available NPSH for AF Pump When Supplied from SX System," Revision 0, dated February 20,1989, " Auxiliary Feed Design Basis Review Team Report," dated December 30,1996 l

1BEP ES-0.1, " Reactor Trip Response," Revision 1C, WOG-1B, approved January 21,1998 1BEP ES-0.2, " Natural Circulation Cooldown," Revision 1 A, WOG-1B, approved October 17, 1997 1BEP ES-1,1, "Si Termination," Revision 1, WOG-1B, approved April 12,1995 1BEP ES-1.1, "Si Termination," Revision 1, WOG-1B, approved January 26,1998 1BEP-0, " Reactor Trip or Safety injection," Revision 1C, WOG-1B, approved January 21,1998 i 1BEP-1," Loss of Reactor or Secondary Coolant," Revision 1, WOB-1B, approved April 12, i 1995

, 1BGP 100-5, " Plant Shutdown and Cooldown," Revision 27, approved January 24,1998

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BAP 1310-8, "Special Procedures / Tests / Experiments," Revision 12, approved May 15,1997 l BAP 1600-1, " Action / Work Request Processing Procedure," Revision 41, approved May 23, 1997 BAP 1600-7, " Minor Changes Which Do Not Change Function," Revision 8, approved l January 27,1993 BAP 1600-14," Processing and Control of Minor Work Activities Completed as Action Requests, Minimal Work Request, or Pre-Reviewed Work Requests," Revision 7, approved August 27, 1997 BAP 1610-8, " Processing Byron Station Design Changes," Revision 16, approved in October 1997 l

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BAP 1610-9, " Engineering Requests," Revision 3, approved April 30,1996 BAP 500-19," Byron Conduct of Engineering," Revision 4, approved March 1,1997 BSEG-7," Roles and Responsibilities of the Byron Engineering Assurance Group," Revision 1, l undated i Byron letter 97-0315," Application for Amendment to Appendix A, Technical Specifications, to Facility Operating License," dated December 30,1997 EAG November Report 1997, dated December 8,1997, David W. Berg i

NEP-04-01, " Plant Modifications," Revision 4, dated March 28,1997 j NEP-04-02, " Exempt Changes" NEP-04-05," Design Change Acceptance Criteria," Revision 0, issued January 1995

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NEP-09-02," System Performance Monitoring and Analysis," Revision 0, dated June 2,1997 NEP-12-02, " Preparation, Review, and Approval of Calculations," Revision 5, issued June 30, 1997 NEP-12-02BY, " Byron Calculation Site Appendix," revision 1, issued June 12,1997 NSWP-A-04, "10CFR50.59 Safety Evaluation Process," Revision 0, dated January 31,1997 NSWP-A-13," Root Cause Investigation Procedure," Revision 1, dated May 5,1997 NTS 454-200-94-05400-02, " Final Resolution to Suction Pressure Trip" NTS 454-230-97-SCAO00028-01,1B Diesel AF Pump Overcrank Lockout, July 17,1997 l NTS 454-400-96-ESS-J02-01, " Design Flow Limiting Orifice" NTS 455-200-97-SCAQ00014-01,2B Diesel AF Pump Overcrank Lockout, May 13,1997 OSR 97-178, " Proposed Changes to Technical Specifications Minimum Condensate Storage Tank Level and Auxiliary Feedwater," dated December 18,1997 (see PIF B1997-03504)

f;PP 97-045, " Auxiliary Feed Flow Verification," special test procedure, approved January 9, 1998 DCP No. 9400210 " Revise Motor Driven auxiliary feed water pump circuit for change over of suction source" DCP No. 9400427 " Revise Auxiliary Feed low suction pressure alarm, SX swapover and pump trio set points" DCP No. 9500367 " Revise the trip settings for molded case circuit breakers for MOVs 1 AF013 A-H" Modification No. M6-0-92-009 C1 " Installation of overload protection and trip for auxiliary building chiller motors" DCP No. 9700391 " Add a filter to the motor driven auxiliary feed water pump suction pressure circuit" l

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