IR 05000245/1997203
| ML20202C236 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 11/21/1997 |
| From: | Durr J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202A741 | List: |
| References | |
| 50-245-97-203, 50-336-97-203, 50-423-97-203, NUDOCS 9712030290 | |
| Download: ML20202C236 (136) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket Nos.: 50-245 50-336 _50-423 Report Nos.: 97-203 97 203 97-203 License Nos.: DPR 21_ DPR-65 _NPF-49
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Licensee: - Northeast Nuclear Energy Company P. O. Box 128 Waterford, CT 06385 ,
Facility: Millstone Nuclear Power Station, Units 1,2, and 3 Inspection at: Waterford, Connecticut Dates: July 22,1997 - October 1,1997
' Inspectors: - T. A. Easlick, Senior Resident inspector Unit 1 D. P. Beaulieu, Senior Resident inspector, Unit 2 A. C. Cerne, Senior Resident inspector, Unit 3 P. C. Ca+aldo, Resident inspector, Unit 1 S. R. Jor s, Resident inspector, Unit 2 B. E. Kor : , Resident inspector, Unit 3 N. J. Blumberg, Sr. Reactor Engineer J. E. Carrasco, Reactor Engineer S. K. Chaudhary, Sr, Reactor Engineer
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L. S. Cheung, Sr. Reactor Engineer T. Fish, Operations Engineer J. T. Furia, Senior Radiation Speciahst T. L. Hoeg, Reactor Engineer J. C. Jang, Sr. Radiation Specialist T. J. Kenny, Sr. Reactor Engineer E. B. King, Security Specialist L. J. Prividy, Sr. Reactor Engineer L. L. Scholl, Reactor Engineer G. C. Smith, Sr. Physical Security Specialist J. H. Williams, Sr. Operations Engineer S. Kelly, NRR/MEB S. S. Sandin, AEOD/ ERB T. G. Scarbrough, NRR/MEB S. G. Tingen, NRR/MEB P. Bezier, NRC Contractor J. C. Higgins, NRC Contractor M. Holbrook, NRC Contractor S. M. Wong, NRC Contractor A. du Bouchet, NRC Contractor
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M. Shlyamberg, NRC Contractor Approved by: Jacque P. Durr, Chief Inspections, Special Projects Office, NRR i
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TABLE OF CONTENTS
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EXECUTIVE SUM M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv U1.1 Operations ............................. .................... 1 U1 O1 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 1 U108 Miscellaneous Operations issues , , . . . . . . . . . . . . . . . . . . . 3 U 1.Il M ain t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 U1 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 U 1.Ill Enginee ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 U1 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . ........ 6 U1 E7 Quality Assurance in Engir'eering Activities . . . . . . , , . . - . . , 8 l l
U2.4 Operations .................................................13 l'2 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . , 13 U2 O2 Operationel Status of Facilities and Equipment ..........,14 i U2 03 Operations Procedures and Documentation . . . . . . . . . . . . . ,15 U2 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . 17 U2 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . 18 U 2.ll M aint enan ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 U2 M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . 21 U2 M3 Maintenance Procedures and Documentation . . . . . . , , . , 21 U2 M8 Miscellaneous Maintenance issues , , . . . . . . . . . . . . . . . . . 22 U 2.lll Enginee ring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3 U2 E1 Conduct of Engineering , , . . , , , . . . . , , , , . . . . . . . . . 23 U2 E8 Miscellaneous Engineering issues . . . . . . . . . , , , . . . . . . . 24
3.1 Operations ,................................................38
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U3 O1 Conduct of Operations . . . . . . . , . , . . . , , . . . . . . . . . . . 38
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U3 02 Operational Status of Facilities and Equipment ....,, ... 42
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U3 03 Operations Procedures and Documentation . . . . . . , , . . . . 43 U3 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . 47 U3 07 Quality Assurance in Operations .................... 48 U3 08 Miscellaneous Operations Issues . . . . . . . . . . . . . . . . . . . . 50 U 3.ll M ainte nan ce . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 5 U3 M1 Conduct of Maintenance , , . . . , , . . . . . . . . . . . . . . . . 5 5 U3 M2 Maintenance and Material Condition of Facilities and Equipment
...........................................55 U3 M8 Miscellaneous Maintenance issues . . . . . . . . . . . . . . . . . . . 59
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U 3.Ill Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
~ U3 E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 U3 E2' Engineering Support of Facilitis.1 ?nd Equipment ..........65 U3 E3 Engineering Procedures and Documentation ............71
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U3 E8 Miscellaneouu Engineering issues . . . . . . . . . . . . . . . . . . . . 72 IV Plant Support .................................................95 Radiological Protection and Chemistry Controls . . . . . . . . . . 95
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. R1 R8 Miscellaneous Radiological Protection and Chemistry issues . 99 S1- Conduct of Security and Safeguards Activities . . . . . . . . . 101
- S2- Status of Security Facilities and Equipment . . . . . . . . . . . . .102
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SS Security and Safeguards Staff Training and Qualification . . 103
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SS Miscellaneous Security and Safeguards issues . . . . . . . . . 104
V. Engineering Multiple Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105 E1 Conduct of Engineering . . . . . . . . . . . . . . . . , . . . . . . . . . 105
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E8 Miscellaneous Engineering Issues . . . . . . . . . . . . . . . . . . . 115 VI. Management Meetings .........................................118 X1 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . 118
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4 EXECUTIVE SUMMARY Millstone Nuclear Power Station Combined inspection 245/97 203;336/97-203;423/97 203 i Operations e An independent assessment was performed by the licensee to verify the quality of an exceptionally high number of Condition Report (CR) evaluations completed over a relatively short period of time. Over 800 level 2 CRs were
- evaluated during the month of June 1997,in response to management's focus on the reduction of backlogged 1997 CRs that required investigations. The result of the assessment indicated that 65% of the 87 sampled CRs reviewed were found to be acceptable. The CRs that were unacceptable were primarily associated with human performance elements not being addressed, or the
, generic implications not being addressed. Licensee management has requestei that the sample size be expanded and an additional review be conducted. This issue will remain unresolved pending completion of the licensee's review and followup by the NRC. (Section U1.01.2)
e At Unit 2, the Facility 1,4160 Vac vital bus was lost while shifting from the normal station service transformer to the reserve station service transformer (RSST). A blown fuse two days earlier caused an engineered safeguards actuation system (ESAS) cabinet to become partially deenergized. Operators did not sufficiently evaluate the effect of the partially deenergized ESAS actuation cabinet, which was now sending a load shed (open) signal to the RSST output breaker. (Section U2.01.1)
e On September 24,1997, the licensee determined that Facility 1 and 2 ESAS
.. cabinets were inoperable because new power supplies that were installed in a 1994 'nodification could have blown the power supply fuses if an ESAS actuation were to occur, thereby preventing the actuation safety equipment.
This condition was reported in accordance with 10 CFR 50.72(b)(2)(iii)(D). At the end of the inspection period, NRC and licensee evaluation of this concern was ongoing and will be covered in a future NRC inspection report. (Section U2.01.1)
e At Unit 2, much of the work associated with upgrading emergency operating procedures (EOPs) and Abnormal Operating Procedures-(AOPs) that the licensee plans to complete prior to restart is stillin progress. The licensee's efforts to determine which EOP support procedures need revision were found to be comprehensive. NRC concerns discussed in Inspection Report 95-21-associated with pre-staging of EOP equipment and human f actors have been
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effectively addressed. AOPs selected for revisions before restart were found to be appropriate. A review of the procedures required by Regulatory Guide 1.33 raisad concerns regarding the adequacy of the procedural guidance for iv
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the loss of containment integrity and is considered unresolved. (Section U 2.03.1 )
- At Unit 2 has been successfulin addressing the longstanding problems associated with tagout adequacy as demonstrated by good performance over an extended period. Strong self-assessments and corrective actions associated with tagging has been the driving force behind continued improvements in this area. (Section U2.08.1)
- At Unit 2, inspectors pa;d particular attention to shift turnovers and pre-evolution briefings which were found to be very thorough, and there were good questions and discussions among participants. In addition, the evolution to fill the "A" low pressure safety injection pump piping, which involved temporarily securing spent fuel pool cooling, was well planned and conducted, and included extensive management oversight during the preparation and perfor .ance of the evolution. (Sections U2.01.1 & U2.01.2)
- Continued Unit 3 material, equipment, and parts list (s) (MEPL) questions and operations and work control management of plant configuration for planned evolutions merit additionallicensee management attention. (Section U3.01.1)
- While both the Restart Verification and Recovery Oversight review activities appear to be positive efforts in demonstrating the Nuclear Oversight organization's integrated assessment of the Unit 3 readiness to restart, the results of such rigorous evaluations (e.g., corrective action) have not yet resulted in improvement. (Section U3.07.1)
- Technical Specification (TS) revisions regarding organizational changes have improved. This resulted from actions to correct a violation for an improperly instituted management reorganization at Millstone Station. (Section U3.08.1)
- Unit 3 staff effectively addressed the performance issues identified in LERs related to Technical Specification noncompliances. Licensee personnel accurately determined the cause(s) of deficient performance and identified appropriate corrective actions that addressed immediate concerns and the apparent root causes. (Section U3.08.2)
Maintanance
- The inspector observed work associated with the replacement of the gas turbine (GT) hydraulic power unit motor. While there were no deficiencies noted with the actual work performed, following questions by the inspector, nuclear oversight identified that the automated work order (AWO) had not received the required quality control (OC) review ac required by WC 8003. A review of other GT work orders identified that an AWO conceming surveillance testing of the CO 2fire system on the GT also had not received the required OC reviews. The failure to perform the proper QC review is a violation of v
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n Technical Specification 6.8.1. Additional reviews of AWOs initiated since May 15,1997, when WC 8003 was revised, indicated 14 other AWOs were improperly coded during planning. At the end of the inspection period, the i
licensee was conducting a review of all surveillance testing to ensure proper QC reviews. WC 8003 was revised in May to resolve a previously identified
_ problem with QC involvement in the work planning process.- As processes and procedures continue to be changed, plant personnel need to be properly
- trained with new expectations continually reinforced. (Section U1.M1.1)
- At Unit 2, a detailed walk down of the control room air conditioning system was performed and overall material condition was found to be acceptable. ;
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Sealing of duct joints and penetrations was noted to be particularly good.
(Section U2.02.1)
- At Unit 2, the followup inspection of Escalated Enforcement item 50 336/96-08-08 was performed, which concerned the failure to review the adequacy of
technical specification required valve lineups, as committed to in an LER. The ,
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licensee reviewed a total of 16 valve lineups and identified problems with 13.
A total of 67 small vent, drain, instrument root and process flow valves were-missing from these 13 syc+em lineups. The licensee's review was found to be acceptable. (Section U2.M8.1)
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- The licensee appropriately addressed specific Rosemount transmitter shipping plug problems identified in the previous NRC inspection report. However, 4 . some problems were noted in the broad corrective and preventive actions J
implemented thus far. These problems included performing a sampling
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inspection of plant instrumentation instead of a complete review as described l in the correrive action plan and inappropriate closure of the related action requests. (Section U3.M2.1)
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- The design change to alleviate the problem of potential plugging and erosion of ECCS throttle valves in the emergency core cooling system has been l physically completed, however, more work is required to close the design change. This item is considered an apparent violation. (Section U3.M8.1)
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Engineering
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- Unit 1 engineering calculation Pen X 42, for penetration X-42 in the standby i liquid control system, demonstrates the design adequacy of the existing double anchor configuration at containment penetration X-42, it further
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shows the newer tube steel anchor to be redundant. Regarding the document s control failure which necessitated the new evaluation effort, the Design Control Manual now specifies detailed documentation requirements for all design processes. When properly adhered to, the procedures should minimize
such document control failures, it is concluded that the licensee's corrective actions appropriately address the issues identified in the subject CR. (Section U 1.E 1.1 )
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- The Unit 1 response to a nucicar oversight identified issue concerning the installation of temporary lead shielding in the plant, was prompt and comprehensive.- Additional shielding concerns were identified by the licensee,-
as well as indications of a larger programmatic problem. At the end of the inspection period, design engineering was evaluating existing shielding packages and assisting Health Physics in the review of shielding installations.
The root cause for the programmatic problems was under review by the licensee.- Additional reviews of other plant programs was also being conducted by the licensee at the end of the inspection period. This issue wil!
remain unresolved pending completion of the licensee's evaluation of the program. (Section U1.E1.2)
e The Unit 1 operating experience (OE) staff is highly qualified and very dedicated to making a positive contribution to the line organization. A critical self assensment review and the associated corrective action plan have provided a method of improving the effectiveness of the OE group. In June and July 1997, a significant reduction in ba%Iog was achieved due to the ,
Backlog Reduction Project. However, an increase in the median age of the backlogged evaluations would indicate that less emphasis was placed on the older evaluations versus the newer ones. The prioritizaNn of the work, particularly in the case of the large backlog, needs more management attention with clear expectations on how to prioritize t5e work load. The interface agreement that was signed by the recovery officers and the vice president nuclear oversight excluded the Nuclear Safety Energy Group (NSEG)
department. This caused the NSEG staff to question both management's commitment to the group, as well as their function and position at the site.
(Section U1.E7.1)
e The "A" emergency diesel generator (EDG) at Unit 2 was rendered inoperable due to a vibration induced weld joint failure that resulted in the spill of 5 to 7 gallons of lube oil before the diesel was secured. The failed weld, as well as many other welds on the skid mounted piping for both the "A" and "B" EDG, were found to be partial penetration welds (% to 2/3 of piping thickness), not full penetration welds as specified by the EDG vendor. The licensee determined that based on the review of the vibration data, inspections of the available pipe welds and successful code stress analysis, failure of the "B"
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'DG skid mounted piping coincident with the "A" EDG was not considered credible. The licensee's plans to rework and establish full penetration welds for the "A" and "B" EDG were found acceptable. The associated licensee event report will be reviewed in a future NRC inspection report following licensee completion of necessary corrective actions. (Section U2.E1.1)
^* . Unit 2 is taking proper steps toward the completion of the analytical evaluation of water hammer loads that caused significant damage to piping supports in the suction piping from the refueling water storage tank.
However, this piping support damage raises questions regarding the adequacy vii
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of the licensee's response to NRC Bulletins 79-02 and 7914 and is considered unresolved. (Section U2.E8.1)
- At Unit 2, the operations critical drawing of the control room exht.ust duct incorrectly reflected a fire damper and two srnoke detectors as being located
outside the control room boundary when they are actually inside. This-discrepancy does not effect system operation and was characterized as a Non-Cited Violation. (Section U2.02.1)
- Unit 2 corrective actions were acceptable to address the concern that the i containment sump screen mesh could pass debris of sufficient size to clog the
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high pressure safety injection discharge throttle valves. (Section U2.E8.2)
- The fact that the Design Control Manual (DCM) does not specifically address the temporary modification design process, however, is considered a weakness, inclusion of this process in the DCM would strengthen recognition that the temporary modification procers is a quality design activity and l requires design practices commensurate with that classification. (Section U2.E8.4)
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- The newly instituted design engineer training program at Unit 2 :s considered positive, it should provide the means to convey to the engineering staff their expected level of knowledge and management expectations in that regard. As a minimum,it should allow a clear classification of the capab;lities of each engineer and a matching of talents to job requirements. (Section U2.E8.4)
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- At Unit 2, after completing the permanent modifications to address seismic
- concems associated with the reactor building closed cooling water (RBCCW)
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surge tank, the NRC found the design calculation was inadequate due to
incorrect assumptions regarding the use of wire rope supports that were installed. Discussions with the licensce indicated they were already aware of
, the inadequacy due to a Nuclear Oversite audit team identifying the same concern, reflecting positively on Nuclear Oversite performance. However, design engineering should have identified this issue. (Section U2.E8.41
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- There is currently no effective method for tracking material, equipment and parts lists (MEPL) status on consumable items or ensuring that any requirements established in the MEPLs are met during the purchase and use of the item, in addition, the hard-copy MEPL, which is used for items without specific component identification numbers has not been kept up-to-date.
(Section U3.E3.1)
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- The actions taken by Unit 3 management to address calculational discrepancies related to the turbine-driven auxiliary feedwater pump (TDAFWP)
are acceptable. The replacement calculations correct the deficiencies that were identified, and provide an adequate basis for the evaluation of TDAFWP performance. The vendor review procedure and the ongoing assessment of
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critical calculations are both considered reasonable methods for improving the design control process. They should improve the quality of the calculation databases by providing assurance that they are comprehensive and correct.
(Section U3.E8.2)
- Unit 3 revisions to the Corrective Action Program and Design Control Manual were considered enhancements and should have a positive impact on the design control process. In particular, the establishment of the corrective action manager with an experienced staff provides a level of impartial and knowledgeable oversight to the process that was missing in the former program. (Section U3.E8.4)
- The licensee used "DBE 50*C equivalent life," based on the Arrhenius equation, in its environmental qualification calculations for post accident operating time extrapolation (PAOTE), without providing a sound technical basis for its use. This issue affects all three units. (Section U3.E8,5.1)
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- A non-cited violation was identified involving two pressure switches at Unit _3 that were not in the Unit 3 EQ master list. (Section U3.E8.5.2)
- The licensee provided an extensive evaluation for a Unit 3 Condition Report
involving unqualified solenoid valves at Unit 2, to determine if Unit 3 had similar deficiencies. However, the licensee's verification process failed to include a walkdown of the identified solenoid valves in the post-accident-sampling-system to ensure that these valves met the design requirements.
(Section U3.E8.5.3)
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- The licensee completed extensive self-assessment audits on the Unit 3 e environmental qualification program, covering all major areas of this program.
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These audits resulted in a number of good findings, which require resolution
! before startup. (Section U3.E8.5.4)
- An NRC site wide review of the Vendor Evaluation Technical Information Program (VETIP) noted that all activities associated with meeting commitments of Generic Letter 90-03 should be in place and fully implemented prior to startup. The majority of these items were verified to be in place during this inspection. However, the July, 11,1997, NU letter, B16629, defers some of
, these commitments to January,1999. The NRC does not concur in the 4 deferrais as described in that letter; and notes that, since the letter, additional
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- items have been undertaken to be completed before startup. (Section V.E1.1)
- NU has allocated substantial resources in a new motor operated valve (MOV)
organization in order to correct program deficiencies However, the changes
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modifications, overhauls, and testing remain to be completed. (Section V.E1.2.5)
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- Additional justification will be needed to support the design basis differential pressure and long term thrust requirements for the Units 2 & 3 power operated
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relief block valves. (Section V.E1.2.3)
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e NU's actions to address pressure locking and thermal binding concerns regarding motoi operated gate valves remain under evaluation by the NRC.
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The licensee agreed to provide a supplemental response to Generic Letter 95-07, " Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves," to address assumptions in the pressure locking calculations for certain Unit 2 MOVs. In this response, the licensee also will discuss their corrective actions to a violation regarding a procedure which failed to address thermal binding concerns for the Unit 2 turbine driven auxiliary feedwater i
pump ateam admission valves. (Section V.E1.2.4)
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. Plant Support
- The licensee has made improvements in the ALARA program at Unit 3, and efft.etively implemented a program for the control of potentially radioactive
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materials released from the site. One violation of NRC requirements was
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identified, however, in the area of radiological worker practices. (Section I VI.R1.1 )
- A violation of NRC requirements in the transportation program was also identified during this inspection period. A package of radioactive materials was sent to another facility which, upon receipt, was determined to have external radiation levels in excess of regulatory limits. (Section VI. R1.3)
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e Overallimplementation of the Security Plan was found to be acceptable. The violation associated with control of vehicles in the protected area will remain-open pending an evaluation of the effectiveness of the pilot program recently put in place to address the weakness and fullimplementetion of the corrective actions. (Section VI.S)
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Summarv of Plant Status Unit 1 remained in an extended outage for the duration of the inspection period. The licensee continues to implement configuration management program (CMP) activities,
- engineering reviews, and docketed correspondence assessments to verify compliance with the established design and licensing basis of the unit. The successful completion of these activities is required by NRC order prior to restart of the unit. While there is a reduction of a restart activities at Unit 1, through the end of this year, configuration management program activities continue. Following a reduction of the contractor work force for the CMP project, approximately 48 plant personnel from operations, engineering, and maintenance _are currently assigned to work on the CMP. Additionally, Unit 1 maintenance personnel are providing support for the ongoing restart efforts at Unit 3, U1.1 Ooerations
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U101 Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing
, plar t operations. During this period the licensee continued performing activities associated with the restoration of the emergency diesel generator (EDG), which was being restored
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following ran extended outage for maintenance and modification work. There was a sigtificant effort on the part of the Unit 1 staff to return this system safely and officiently to an available status for shutdown risk considerations. The unit reached its goal of
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attaining a shutdown risk level of " Green," the highest of three risk levels, following the restoration of the EDG to an available status.
01.2 Assessment of Condition Reoort Evolutions (SIL 17 Update)
- a. insoection Scone (71707)
4- An independent assessment was performed by the licensee to verify the quality of condition report (CR) evolutions that were reviewed and approved between June 1,1997 and July 3,1997. The primary focus of the assessment was the comparison of the problem description to both the causal factors and the associated corrective actions. The j- inspector reviewed the assessment report and observed management's response to the findings, b. Observations and Findinos -
" Corrective Action Program," RP-4, requires level 1 and 2 CRs to be evaluated and corrective action plans developed within 30 days of the initiation of the CR. In May 1997, Unit 1 management set a goal to eliminate the backlog of 1997 CRs out for investigation, which were greater than 30 days old. Specifically, the goal was to have all 1997 CRs complete through the evaluation process by the end of June. As a result of this initiative,
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plant personnel processed over 800 CRs during the one month period. Based on the exceptionally high number of CRs which were processed over a relatively short period of time, licensee management determined that an assessment of CR evaluation quality would be prudent. The ori 0inal scope of this assessment included 20% of the level 2 CRs evaluated during that period. Also included in the scope, was an expectation that the sample size be expanded if the percentage of CR acceptability, based on technical merit, was less than 90%. Level 1 CRs were not considerea in this review since they are subject to a management review team (MRT) review of the evaluation results and the corrective action plans.
The assessment was completed and a report was issued on August 8,1997. The review included 87 CRs (11% of the total CRs evaluated during tb 4t period) selected on a random basis. The results of the assessment indicated that 65% a the CRs reviewed were acceptable. A breakdown of the remaining 35% of the CHs that were unacceptable, generally fellinto one of three categories: 1) the human performance element of the problem was not addressed: 2) the generic implications were either not addressed, too narrowly focused, or did not have a corrective action; or 3) no causes were identified or the cause did not relate to the r,ctrective action. The experience assessment department initiated a CR, M1-971939, to document the findings of the report.
The Director, Unit Operations requasted a Plant Operation Review Committee overview meeting to review the findings and evaluate the recommendations in the report. On the day of the scheduled PORC overview, a quorum of PORC members could not be reached so the experience assessment department presented the report to the members of management that did attend. The inspector observed the meeting and subsequently discussed a number of concerns with the Director, Unit Operations that the human performance and generic implications were not considered a factor, and the staff appeared to be focussing on the third category of unacceptable CRs, suggesting and were a reflection of the maturity of the currer' program, and they were being compared to a higher standard of excellence. The inspector also questioned why the review was limited to 11 % of the total population, when the initial review plan called for a 20% sample.
Additionally, the sample was not expanded based on the less than the 90% success criterion.
A subsequent PORC overview was conducted, and the results of the assessment were presented by the manager of the experience assessment department. During that meeting, all of the inspector's concerns were discussed and addressed. As a result, the licensee planned to expand the sample and use trending data to identify common problem areas.
The plar, also included making appropriate corrections where specific issues were identified. Discussions with the manager of the experience assessment department indicated that an additional barrier will be put in place to perform a quality review of the level 2 CRs in the final closure process, before the CR packages are sent to nuclear records. This issue will remain unresolved pending a review of the final assessment including an expanded sample of the original 800 CRs evaluated. (URI 245/97-203 01)
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c. Conclusion An independent assessment was performed by the licensee to verify the quality of an exceptionally high number of CR evaluations completed over a relatively short period of l time. Over 800 level 2 CRs were evaluated during the month of June 1997, in response to ,
management's focus on the reduction of backlogged 1997 CRs that required investigations. I
, The result of the assessment indicated that 65% of the 87 sampled CRs reviewed were l found to be acceptable. The CRs that were unacceptable were primarily associated with human performance elements not being addressed, or the generic _ implications not being addressed, t.icensee management has requested that the sample size be expanded and an additional review be conducted, This issue will remain unresolved pending that review.
- U108 Miscellaneous Operatione issues-08.1 (Closed) Violation 245/95-044-03 and 04 Failure to orovide authorization orior to exceedina overtime limits a. Insp3ction Scoce (92901)
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The inspector reviewed the corrective action implementation in response to two violations associated with exceeding overtime limits.
I b. Observations and Findinas The violations cited the licensee for failing to control the overtime hours worked by Unit 1 personnel performing safety-related maintenance and engineering activities. One individual was a contractor and the other, a test engineer. The licensee stated in the reply to the violations that the cause, in general, was due to failure of management to hold personnel
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- accountable for performance, to adequately define expectations for compliance with the procedure NGP 1.09, " Overtime Controls for Nuclear Group Personnel," and the inadequate monitoring of performance. The licensee revised NGP 1.09, " Overtime Controls for all Personnel at Millstone Station." The procedure now applies to all personnel and contractor personnel who work at Millstone. The procedure also applies to all work, regardless of whether personnel perform safety or non-safety functions, la the caso of safety-related
. work, Attachment 3, " Authorization to Exceed Established Overtime Limits," will be used to document overtime and will be retained as a 5-year record. For non-safety related work, local management will control and document overtime.
- c. Conclusion The licensee's corrective action to address the violations were determined to be acceptable, and therefore, this item is closed. The revision to NGP 1.09 clearly explains management's expectatbns for procedure applicability, for both the individuals and the type of work that is performed.
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U1.Il Maintenance U1 M1 Conduct of Maintenance M 1,1 Gas Turbine Generator Maintenancs (SIL 30 Update)
a. Inspection Scone (62707)
The inspector observed work associated with the replacement of the gas turbine (GT)
hydraulic power unit (HPU) motor, performed under automated work order (AWO) M197-09056, b, Observations and Findinas I
On August 25,1997, the inspector observed the motor replacement work performed by two maintenance electricians using a two-page Automated Work Order (AWO) for guidance
- and direction. - The AWO job description included: 1) disconnect and remove existing HPU moto ; 2) install and connect rebuilt motor; 3) lug the terminals, if necessary; and 4) ensure spide a is properly installed. The inspector's initial questions concerned the need for a procedure, since the work was being performed on safety-related equipment. The
....pector noted that the electricians had questions regarding the motor / pump coupling
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assembly, referred to in the AWO as the " spider," The maintenance supervisor was -
present and answered the electricians' questions regarding the coupling assembly. The inspector noted that the work went well and no deficiencies were identified. The inspector-questioned both the system manager and a nuclear oversight inspector who were present -
during the work, if there were any torque requirement when bolting the pump to the HPU
- motor, The system manager was not aware of any vendor specified torque requirements, but stated that he would check on it.
Later that day, nuclear oversight informed the inspector that a review of the planning documentation for the AWO indicated that the AWO had not been reviewed by the Quality Control (OC) group, as required by WP 8003, Rev,0, " Unit 1 Work Package Planning," WP 8003 step 1,17.15 requires that a work order involving a motor replacement shall be
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reviewed by QC. As stated in WP 8003, the only motor work on safety-related equipment that doesn't require OC review is replacement of air filters, screens and cover fasteners.
Subsequently, a three page AWO was generated for the motor replacement, and OC
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- reviewed the work order, in this case, the post maintenance test was adequate to ensure proper installation and that additional QC hold points were not required.
The licensee reviewed all of the associated gas turbine AWOs to verify that the requirements for OC reviews were properly established. The review identified a second-two-page AWO, M197-05332, concerning the performance of a surveillance on the gas turbine CO2 fire system. The surveillance work on the CO2 fire system included the disassembly of components and therefore, a OC review was required, but was nut performed The three-page version of the AWO was also reviewed by QC, and in this case,
- OC hold points were required. This necessitated reworking the surveillance with the appropriate OC involvement,
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The licensee subsequently expanded their review to include all AWOs initiated since May 15,1997, when WC 8003 was revised, to provide guidance for when a OC review is required. The review included 295 AWOs, and identified an additional 14 AWOs that
- required a OC review per WC 8003. Three of the 14 AWOs needed to be reworked since QC hold points were required to verify torquing on the three reactor building closed cooling water heat exchangers. The licensee also revised WC 8003 which added exceptions to step 1.17,15 for safety-related work that does not require QC review. The revision encompassed the remaining 11 AWOs identified in the review, and therefore, no rework was needed. The licensee also expanded their review to include surveillances, based on the gas turbine CO, fire system surveillance issue. Considering the large number of
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surveillances in this review and the amount of time it would take to complete, the licensee revised WP 8009, " Surveillance Scheduling, Performance, and Tracking," to include the list of exceptions from WC 8003, and guidance to review each surveillance procedure prior to performance, At the end of the inspection period, the surveillance review was continuing.
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The follow up inspection of the HPU motor replacement work and the reviews conducted
. by the licensee, indicated that there were no specific torque requirements for the motor / pump bolts. The training requirements for the coupling assembly work was also reviewed, and although the maintenance technicians received specific training on the flexible coupling assembly, the electricians did not. This training will be added to the ;
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electricians training program. The failure to properly ensure that safety-related work is correctly coded and reviewed by OC constitutes a violation (VIO 245/97-203-02) of Technical Specification 6.8.1, which requires hat written procedures be established.
implemented, and maintained for activities rewenced in Appendix A of Regulatory Guide 1.33, " Quality Assurance Program Requirements (Operation)," Revision 2, February 1978.
Item 9 a., " Procedures for Performing Maintenance," recommends that maintenance that
! can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures. WP 8003, " Unit 1 Work Package Planning," step 1.17.15, requires that if work has a quality indicator of "Y" or "U" or
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involves non-QA code welding, indicate "QC required," "Yes," except for the following activities:
- Motor: Replace air filters, screens, and cover fasteners, or
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e Tests and calibration (rion-EEO): Any test or calibration that do (sic) not disassemble systems beyond designed access covers.
Contrary to the above, on August 25, and August 29,1997, work with a quality indicator of "Y," indicated "QC required," "No" and did not meet the exceptions stated in step 1.17.15 of WC 8003. The work involved: 1) AWO M197-0956, Gas Turbine Hydraulic Pump Motor Replacement; and 2) AWO M197 05332, Unit 1 CO, Fire System Surveillance Testing, wh!ch required disassembly of the components in the system.
c. Conclusion The inspector observed work associated with the replacement of the gas turbine hydraulic power unit motor. While there were no deficiencies noted with the actual work performed,
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i following questions by the inspector, nuclear oversight identified that the automated work order had not received the required quality control (OC) review as required by WC 8003. A review of other GT work orders identified that an AWO concerning surveillance testing of '
the CO, fire system on the GT also had not received the required OC revieva. The f ailure to perform the proper QC review is a violation of TS 6.8.1. Additional reviews of AWOs mitiated since May 15,1997, when WC 8003 was revised, indicated 14 cthat AWOs were improperly coded during planning. At the end of the inspection period, the licensee was ;
conducting a review of all surveillance testing to ensure prok OC reviews. The licensee should include the results of that review and associated corrective actions as part of the violation response. WC 8003 wer revised in May to resolve a previously identified problem with OC involvament in the work plannirg process. As processes and procedures continua to be changed, plant personnel need to be croperly trained with new expectations continually reinforced.
U1.Ill Engimerina U1 E1 Conduct of Engineering E1.1 Redundant Anchor at Penetration X-42 a. Insoection Scooe (37551)
The inspector reviewed the licensee's corrective actions to close Condition Report (CR) M1-97 1062, b. Ohnrvations and Findinns During a Unit 1 walkdown, the inspector noted the existence of an anchor restraint at the flued head penetration X-42 for Standby Liquid Control Line No.1 %-SLC-6. Since the flued head itself is typically an anchor, the necessity for this additional anchor was questioned.
The licensee issued Condition Report (CR) M197-1062 to investigate this finding and to retrieve and or develop documentation to demonstrato the adequacy of the support arrangement. Upon review, the licensee could not justify the adequacy of the dual anchor field condition and concluded that this was a failure to properly document the NRC Bulletin 7914 program evaluations. As corrective actions, the licensee developed documentation to justify the acceptability of the current installation, investigated the feasibility of removing the extra anchor, and observed that the Design Control Manual (DCM) would provide better control of documentation for futu a field deviations.
The new documentation to justify the acceptability of the current installation, consisted of calculations which characterized the interactions between the two, closely spaced, anchors. Since the two anchors are within 12 inches of each other, the two anchors have no effs;:t on the stress calculations that qualify the associated standby liquid controlline piping. Instead the concern, and the focus of the calculations, was the effect the ancnors had on each other. The inspector reviewed the calculation Pen X-42, dated May 21,1997.
The calculation results showsd that the interaction stresses were all within allowable levels. At the inspector's request, the calculations were revised to include an estimate of
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piping thermal expansion effects, correction of a minor error and consideration of an additional critical cross section. The stress estimates from the revised calculations, although higher, were still acceptable. The kispector concurred with the licensee's finding that the existing configuration is acceptable.
The licensee also extended the calculations to determine if the flued head anchorage alone rsld support the pipe stress calculation anchor reaction loads. The ;ritical section was identified as the weld located at the flued head to-piping connection. Yne etress levels at this weld were higt but acceptable. The licensee cancluded that the tt b3 steel anchor was redundant and its removal wou!d not compromise the adequacy of the system design. At the inspector's request, the licensee expanded this ieview to ensure that loads or conditions not yet considered would not reverse this conclusion, c. Conclusions Licensee calculation Pen X 42, demonttrates the design adeouacy of the existing doub;e anchor configuration at containment penetration X-42. It further shows the newer tube steel anchor to be redundant. Regarding the document control failure which necessitated the new evaluation ef fort, the DCM now specifies detailed documentation requirements for all design processes. When properly adhered to, the procedures should minimize such document control failures, it is concluded that the licensee's corrective actions appropriately adoress the issues identified in the subject CR.
E1.2 Unit 1 Temocrarv Shieldina Proaram a. inspection Scooe (37551)
The inspector reviewed the licensee's response to a nuclear oversight identified issue concerning the placement of temporary lead shielding on an 8" pipe (FPC-2) between 1-FP-1, fuel pool cooling (FPC) suction valve, and a penetration to the shutdown cooling heat exchanger room. The oversight inspector was making preparations to perform an audit of the Unit 1 temporary shielding program. He identified that tcmporary shielding request (TSR) 1 95-012, installed temporary lead shioding for a 5-day evolution in October of 1995, and his initial walkdown verified that the shielding was stillin place. Condition report (CR) M1-97-1764 was written to document this issue and nuclear oversight questioned if the system was in an unanalyzed condition, b. Observations and Findinas Following the initiation of CR M197-1764, the operations department initiated an operability determination, which was prepared by design engineering, to answer the question of whether the system was being operated in an unanalyred condition. The structuralintegrity of the FPC system was assessed due to the addition of approximate!y 80 lbs of lead shielding on the 8" pipe near 1-FP-1. Design engineering performed a walkdown of the area and determined that the penetration surrounding the pipe was feirly tight, with a small gap filled by firestop-type material. Engineering also performed a seismic analysis which included the additional lead weight. The results of the analysis
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l indicated that the piping stresses were within code allowable limits, and therefore, the system is fully qualified with the lead in place. ;
As a result of the CR, health physics (HP) management performed a comprehensive review of all existing shielding packages. Additionally, HP began a review of the shielding program at Unit 1. These reviews, as well as plant walkdowns identified 44 shielding applications on the unit. HP determined that there was a lack of an overall program evaluation process, and that rigging and attachment devices had not been evaluated or controlled, in addition, inadequate interf ace among organizations was also cited as a problem.
Corrective action plans are being developed that will include the HP department assuming ownership of the Unit 1 shielding program. Additionally, a stand-alone shielding procedure will be developed, since the TRS forms are currently an attachment to WP 8003, " Unit 1 Work Package Planning." The inspector discussed with the licensee how these programmatic f ailures occurred, and as a result, the licensee issued CR M 197-2135, as a level 1 CR, to determine the cause for the lack of ownership that lead to the failure. The inapsetor also discussed with licensee management other programs that could have similar problems to those identified in the shielding program. That issue will also be addressed in a separate CR (M1-97 2090). These issues will remain unresolved (URI 245/97 203-03) pending completion of the root cause analysis and the final design engineering reviews, c. Conclusions The licensee's response to a nut, lear oversight identified issue concerning the installation of temporary lead shielding in the plant, was prompt and comprehensive. Additional shielding concerns were identified by the licensee, as well as indications of a larger programmatic problem, At the end of the inspection period, design engineering was evaluating existing shielding packages and assisting HP in the review of shielding installations. The root cause for the programmatic problems was under review by the licensee. Additional reviews of other plant programs were also being conducted by the licensee at the end of the inspection period. This issue will remain unresolved pending completion of the licensee's evaluation of the program.
U1 E7 Quality Assurance in Engineering Activities E7.1 Unit 1 Nuclear Safetv Ennineming (SIL 108 Update)
a. Insoection Scooe (40500)
The inspector reviewed the nuclear safety engineering (NSE) group at Unit 1, which performs the operating experience evaluation function for that unit. The inspector conducted interviews with the operating experience (OE) assessment staff, reviewed procedures, and observed the interaction between the group and the line organization.
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b. Observations and Findinas The NSEG at Millstone is a part of the Nuclear Oversight organization, working under the Director, An niysis and Program. Activities are conducted under site-wide procedure NOOP-3.04, " Nuclear Safety Engineering Group Function and Responsibilities," and two lower tier instructions, NSEG instruction 3.01, " Operating Experience Evaluation," and NSEG instruction 5.01, "lSEG Evaluation." The independent safety engineering group (ISEG)
function is not currently being performed on Unit 1 due to reduced staffing (ISEG is not a required function on Unit 1). The Unit 1 OE staff consists of a manager and three engineers. A fourth engineering position is billeted, but currently vacant. Additional
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manpower constraints are placed on the group as OE engineers are temporarily assigned to other plant activities such as the configuration management program (CMP).
The inspector reviewed a self-assessment performed in March of this year. The assessment was cortpleted by four NSEG staff members and an industry peer. The assessment was thorough and critical, and provided a corrective action plan for improvement of the identified weaknesses. The inspector reviewed the status of the corrective action plan recommendations. Two of the recommendations have been completed and four others are actively being worked, it was apparent to the inspector that the OE staff was determined to improve their effectiveness. Additionally, OE has attempted to become more proactive in their reviews by providing operating experience to the line organization on a "just-in-time" basis. For example, if maintenance is going to perform a freeze seal, OE will review the OE database and network to find relevant information conceming freeze seals. The daily distribution of the "OE Minute," which provides up to date information on external plant events, has been expanded to reach all plant personnel via computer. The OE manager provided a list of in progress OE evaluations to all Unit 1 directors to assist in setting priorities that meet the needs of the line organization. The recommendations identified by OE were documented in condition reports, tracked to completion, and recently are being reviewed to catermine their effectiveness.
The current backlog for the OE group is 107 open evaluations. There was a dramatic reduction in the backlog from June to July of 1997, when the backlog was reduced from 184 to 96 open items. This was the result of the " Backlog Reduction Project," during which time, three contractors worked exclusively for two months on the backlogged work, in addition, NSEG management determined that internal, site-wide LERs would no longer be a required evaluation, but would now be screened for applicability. The inspector requested information on the relative age of the backlogged work. The licen.5ee completed a review on the relative age of the backlogged work and compared it to an April 1997 review. In April,134 open items had a median age of 2.5 months, in September,107 items had a median age of 6 months. During that time period,128 new items were received for evaluation. In spite of the large number of new items, the current backlog continues to decrease. However, the increase in the median age would indicate that less emphasis was placed on older evaluations versus the newer ones. At the end of the inspection, the manager of OE informed the inspector that additional overtime hours would be authorized for the OE staff to work on the large backlog.
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The inspector reviewed the methods for prioritizing the OE work load. When an OE item is received, it is screened and assigned to an individual, who has the responsibility to prioritize his own work. This can lead to problems if that person is assigned to another group on a temporary basis. The new NSEG instruction 3.01 "OE Evaluation," Re;. 4, dated August 5,1997, requires that the OE staff assign a priority to each OE information item using a high, medium, and low criteria in addition, any backlogged work will have to be reviewed and assigned a priority, and to date, this has not occurred. The inspector concluded that additional work is needed in this area. Management needs to provide a stronger influence in the prioritization of work. This is particularly important when dealing with a large backlog.
During interviews with the OE staff, the inspector found that they were highly qualified and very dedicated in making a positive contribution to the line organization. The inspector also noted a morale problem within the group, which resulted from a lack of clear management expectations concerning roles and responsibilities at the interface with the line organizations. An interface agreement between the recovery officers and the vice president nuclear oversight was signed on March 13,1997. The purpose of the agreement was to develop mutual expectation for interfaces and communication between the line, support, and nuclear oversight organization management. However, the line organization .
and nuclear oversight could not come to agreement on whether the NSEG should be part of the line or remain in oversight. In an effort to get the agreement signed, the NSEG was dropped with the intent that this issue would be resolved after the recovery of the units.
The fact that NSEG was left out of this agreement has had a negative impact on the NSEG at Unit 1, leading the group to question their function and position at the site. Some individuals even questioned management's commitment to the group. This issue will affect performance and effectiveness of the NSEG and should be addressed by management.
In addition, interviews with the staff indicated that lack of engineering support was also having a negative impact on the backlogged work. The increased focus on the CMP work has reduced the number of engineers available to perform pl ant activities. This resulted in less access to system engineers that provide information and support to the NSEG staff who perform evaluations.
c. Conclusion The OE staff on Unit 1 is highly qualified and very dedicated to making a positive contribution to the line organization. A critical self assessment review and the associated corrective action plan, has provided a method of improving the effectiveness of the OE group, in June and July 1997, a significant reduction in backlog was achieved due to the Backlog Reduction Project. However, an increase i the median age of the backlogged evaluations would indicate that less emphasis was placed on the older evaluations versus the newer ones. The prioritization of the work, particularly in the case of the large backlog, needs more management attention with clear expectations on how to prioritize the work load. The interface agreement that was signed by the recovery officers and the vice president nuclear oversight, excluded the NSEG department. This caused the NSEG staff to question both management's commitment to the group, as well as their function and position at the site. At the end of the inspection period, management approved additional
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overtime hours in an effort to reduce the large backlog of evaluations. As with any focused effort on backlog reductiori, the quality of the evaluations must be carefully rnaintained and verified. To assess the quality and effectiveness of the OE evaluation ,
process, additional NRC inspection activities will evaluate these areas using NRC !
inspection procedure 40500, " Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems,"(SIL 17) . This inspection will be scheduled prior to the Unit 3 :
startup.
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Report Details
,Summarv of Unit 2 Status Unit 2 entered the inspection period with the core off-loaded. The unit was initially shut
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down on February 20,1996, to address containment sump screen concerns and has
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remained shut down to address an NRC Demand for information (10 CFR 50.54(f)] letter requiring an assertion by the licensee that future operations are conducted in accordance with the regulations, the license, and the Final Safety Analysis Report.
As delineated in the August 14,1996 NRC Confirmatory Order, governing the Independent Corrective Action Program (ICAVP), on September 15,1997, the licensee announced that they had completed the problem identification (" discovery") phase of their Configuration Management Plan for all 63 systems. Af ter the licensee completed discovery on one half of the Maintenance Rule Group 1 systems, in July 1997, the high pressure safety injection system (including the refueling water storage. tank) and the auxiliary feedwater system (including the condensate storage tank) were selected by the NRC for review by the ICAVP independent contractor, Parsons Power Group Inc. Following the licensee's completion of all 63 systems,- the Enclosure Building and the Emergency Diesel Generators were selected to also M reviewed by Parsons, in addition, the reactor building closed cooling water system was chosen for the "out of scope" inspection by the NRC, in part, because it is not one of the "in-scope" inspections being reviewed by Parsons.
In accordance with commitments made to the NRC regarding corrective action progress and documentation of the completed work items, the licensee has provided a number of corrective action completion packages for NRC review. This inspection report documents closure of a number of issues, reflecting progress in the resolution of open NRC inspection items, as well as an indication of the licensee's program to demonstrate corrective action program effectiveness. A number of items involve modifications or other engineering evaluations that have not yet completed. As an on-going process, the NRC will continue to review available closure puckages upon licensee completion of necessary corrective actions.
On August 19,1997, the licensee announced the appointment of Mr. Michael G. Morris as Chairman, President and Chief Executive Officer, replacing Mr. Bernard M. Fox who announced his retirement in February. On September 4,1997, the licensee announced the appointment of Mr. David B. Amerine as Vice President, Nuclear Engineering and Support Servi::es, replacing Mr. Jay Thayer who was on loan from Yankee Atomic Electric Company as a Recovery Officer.
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U2.1 Operations U2 01 Conduct of Operations 01.1 General Comments (71707) (Closed - Sionificant items List Nos. 26.33.34.
and 36)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations, particularly with respect to shutdown risk management controls. Where appropriate, interviews were conducted with licensed operators and other support persunnel to assess the level of control and detail of knowledge being implemented with regard to observed operational evolutions. During this inspection perioc', in addition to the routine tours and observations, the following activities were specifically examined, either in progress, or to address questions bearing on the final disposition of identified problem areas:
- Inspectoro paid particular attention to shift turnovers and pre-evolution briefings which were found to be very thorough, and there were good questions and discussions among participants.
- On July 29,1997, 4160 Vac vital bus for the facility 1 was lost while shifting from the normal station service transforrner to the reserve station service transformer (RSST). A blown fuse two days earlier caused an engineered safeguards actuation system (ESAS) cabinet to become partially deenergized.
Operators agreed with l&C to keep the cabinet partially deenergized to allow troubleshooting but did not sufficiently evaluate the affect of the partially deonergized ESAS actuation cabinet, which was now sending a load shed (open) signal to the RSST output creaker. Licensee Event Report 50-336/97-26, which discusses this event, will be reviewed in a future NRC inspection report following licensee completion of necessary corrective actions, e On September 24,1997, the licensee determined that Facility 1 and 2 ESAS cabinets were inoperable because new power supplies that were installed in a 1994 modification could have blown the power supply fuses if a ESAS actuation were to occur, thereby preventing the actuation of safety equipment. This condition was reported in accordance with 10 CFR 50.72(b)(2)(iii)(D). NRC and licensee evaluations of this concern wer; on-going at the end of the inspection period, and will be covered in a future NRC inspection report.
Other observations and assessments of operations performance are detailed in the sections below.
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01.2- Fillina of Low Pressure Safety iniection Suction PipiD9
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a. Insoection Scooe (71707)
ine inspector observed the performance of Special Procedure, 97-13-02, " Filling of Spent Fuel Pool Cooling to Shutdown Cooling Piping."
D. Observations and Findinas
The low pressure safety injection (LPSI) pumps provide a backup means of cooling the spent fuel pool (SFP) in the event that the SFP cooling pumps become inoperable. The SFP cooling pumps and the LPSI pumps share a common suction line. The branch line to the LPSI pumps had been isolated and drained to support maintenance and Soecial Procedure
- 97 13 02 was prepared to refill this LPSI branch line. Because there is no vent valve in this LPSI branch line, the filling evolution involved temporarily securing the SFP cooling pumps
. and venting the air through the common suction piping back to the SFP Approximately 1000 gallons of water were needed to fill the LPSI branch line piping. The concern with this evolution is that if a large amount of air remained trapped in the common suction piping, the SFP cooling pumps could become air bound and damaged when started. Due to this vulnerability, the Operations Department asked for a safety evaluation be performed and controls for an Infrequently Perforrned Test or Evolution be established for this filling evolution.
The Control Room Operator (CO) e ho was assigned lead for the filling evolution was very familiar with the procedure, the piping configuration, and the contingency actions. During the performance of the Special Procedure 9713-02, there was a great deal of management oversight, including the Unit Director and the Assistant Operations Manager. The filling evolution was conducted without incident and SFP cooling was reestablished.
c. Conclusion The evolution to fill the LPSI pump piping that takes suction from the SPF was well planned
and conducted, and included a great deal of management oversight during the preparation and performance of the evolution.
U2 02 Operational Status of Facilities and Equipment O 2.1 Walkdown of the Control Room Air Conditioninc System
a. insoection Scone (71707)
The inspector used Inspection Procedure 71707 to perform a detailed walk down of accessible portions of the control room air conditioning (CRAC) system. The inspector also reviewed the following documents for system design basis information:
- Final Safety Analy;is Report (FSAR) Section 9.9.10, " Control Room Air Cradmoning ' item"
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- FSAR Section 14.8.4.3.2, " Control Room Habitability"
- Operability Determination No, MP 232 96 for the Control Room Air Conditioning System b. QbservaMons and Findings The CRAC system equipment operability, material condition, and housekeeping were found to be acceptable. Duct joints and penetrations were found to be properly sealed. The inspector reviewed Procedure OP 2315A, Rev.12, " Control Room Air Conditioning System" and Alarm Response Procedure 2590A, Rev. 2, Window C 40, "CRAC in Automatic Recirculation Mode," and found that operation of the CRAC system was consistent with the FSAR.
The inspector identified a discrepancy between the CRAC system as built configuration and Operations Critical Piping and Instrumentation Drawing No. 25203 26027, sheet 3 of 4.
Thn drawing of the control room exhaust duct incorrectly reflects a fire damper,2 HV 205, and two smoke detectors, E 8358 and E 8302, as being located outside the control room boundary when they are actually inside. The safety significance of this disciepancy was minimal because it had no affect on system operability.
c. Cunclusions The overall physical condition of the control room air conditioning system wat, acceptable.
Scalmg of duct joints and penetrations was found to be particularly good. The piping and instrumentation drawing reflected the as built configuration of the system with the exception of the location of the control room ventilation boundary relative to components ir, the exhaust duct. This drawing discrepancy constitutes a violation of minor safety significance and is being treated as a Non Cited Violation, consistent with Section IV of the NRC Enforcement Policy.
U2 03 Operations Procedures and Documentation 03.1 Emergency Ooeretion Prnnedure arMbDorma Ooerating Procedure Uograde fiogram Status (Update Significant items List Nos. 8 and 10)
a. InEocction Scooe (42001]
Unit 2 has an on going program to upgrade the emergency operating procedures (EOPs) and abnormal operating procedures (AOPs). The inspector reviewed the licensee's progrees in addressing the EOP concerns discussed in NRC Inspection Report 50 330'95 21. The inspector also reviewed work on AOPs to determine whether it was being effectively implemented and whether the existing AOPs met the sequirements of Regulatory Guide 1.33-1978, Appendix A. This inspection was specificaly 'oc ised and did not assess all aspects of the program, which has not been completed.
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. NRC Inspection Report 95 21 discussed the licensee's plans to address concerns regarding .
EOP instrument set point uncertaintles. The licensee has identified 28 to 30 potential
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l revisions to set points that they plan to evaluate. Af ter the uncertainties and revised set points have been calculated, the licensee plans to incorporate the more significant setpoint ,
changes into the EOPs prior to start up. l
Some EOP suppor; procedures were found in the 1995 inspection to be inaccurate. The ,
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licensee reviewed the support procedures and identified 71 support procedure changes to be made before restart. The inspector found that the licensee's review of the adequacy of .
the EOP support procedures was thorough. None of the changes had been finalized at the l time of the inspection. l; The inspector reviewed a sample of procedure OPS FORM 2657 3, "EOP Equipment [
lnventory," to verify that EOP equipment was pre staged as necessary. The inspector ;
found that the licensee was keeping track of EOP equipment even while the plant was shutdown. In addition, the licensee's resolution of the human f actors issues associated with the written EOPs described in NRC inspection Report 95 21 were reviewed and found to be satisfactory.
The inspector observed some of the EOP validation in the simulator. The validation process
appeared to be well planned. No problems were observed.
602S The inspector revicwed the AOPs to be revised before restart and found that appropriate
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priority had been given to the AOPs. The licensee is creating a number of new AOPs associated with Appendix R and a loss of DC power, in addition, there are 18 AOPs 1
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scheduled for revision. l The inspector compared the AOPs against the guidance in Regulatory Guide 1.331978 to ,
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verify that procedures were available to cover specific abnormal and emergency events.
The inspector had concerns whether there was sufficient procedural guidance provided for a loss of containment integrity. In many cases, the inspector found that abnormal operating event procedural guidance was provided in annunciator response procedures (ARPs), operatind procedures (ops), and rarveillance procedures (SPs) rather than separate,
" stand alone" AOPs. This approach appeared to be less convenient to use and has the
' potential to delay abnormal event response, c( Conclualont Much of the work associated with upgrading EOPs and AOPs thet the licensee plans to
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complete prior to restart is stillin progress. The licensee's efforts to determine which EOP support procedures need revision were found to be comprehensive. NRC concerns j
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discussed in inspection Report 95 21 associated with pre staging of EOP equipment and human tactors have been effectively addressed. AOPs selected for revisions before restart were found to be appropriate, A review of the procedures required by Regulatory Guide 1.33 raised concerns regarding the adequacy of the procedural guidance for the loss of containment integrity and is considered unresolved. (URI 50 336/97 203 04)
U2 07 Quality Assurance in Operations 07.1 Nuclear Safety Enoineerina a. insonction Scone (40500)
The inspector reviewed the requirements, respcnsibilities, and staffing for the Unit 2 Nuclear Safety Engineering (NSE) departmont and a the backlog of operating experience items.
b. Observations and Findinas The licensee recently developed Nuclear Oversight Department Quality Procedure (NOOP)
3.04, Nuclear Safety Engineering Group Functions and Responsibilities," Revision 0, dated 6/27/97. This new procedure was written to support a recent organizational and programmatic change to the NSEG department. The major change was to combine the independent safety engineering group (ISEG) function and the operating experience (OE)
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function, which are now the main responsibilities of NSEG. ISEO reviews are independent evaluations of plant activities to provide independent verification that these activities are performed correctly and that human errors are reduced as much as possible. OE reviews consist of screening and evaluating NRC, industry and internal operating experience, and vendor notifications to determine its applicability and safety significance, and to determine if there are any safety issues or recommendations for Unit 2.
NUREG 0737, " Clarification of TMI Action Plan Requirements," dated October 31,1980, forwarded post TMl requirements that had been approved for implementation at nuclear power plants. This document contained an itemized listing of requirements for both operating reactors and applicants for an operating license. Two requirements set forth in NUREG 0737 were I.B.1.2, " Independent Safety Engineering Group," and I.C.5,
" Procedures for Feedback of Operating Experience to Plant Staff." Since Unit 2 was an operating reactor at the trne, only implementation of 1.C 5 vras a regulatory requirement.
However, Unit 2 does fulfill an ISEG function, even though it is not a regulatory requirement.
The approved staffing level for the Unit 2 NSEG consists of a supervisory position and four full time equivalent (FTE) positions. Of the four FTE positions, one la vacant, another may be vacant within a month, the third is en loan to a special project, probably through the end of the year, and the fourth is filled. The supervisor is trying to obtain contractor assistance to help with the work load through the end of the year.
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The inspector reviewed NSEG monthly reports for Unit 2 for the period December 1996 through August 1997. The operating experience backlog was 70 items in December 1996.
An average OE backlog for a typical plant in the nuclear industry is about 70 items. By the end of July 1997, the backlog had grown to 187 items. The inspector discussed the large increase in the backlog with the Unit 2 NSEG supervisor . The biggest reason for the increase was a large increase of operating experience generated within the nuclear industry during this time period. Also, to a lessor degree, was the addition of other categories of operating experience to be reviewed by NSEG that was previously being reviewed by other parts of the licensee's organization. A lesser contributing factor was a temporary reduction in the number of people working in the grcup, due to special assignments to other parts of the organization. Due to the talent level of these individuals, they are highly desirable for use in special assignments. Near the end of the inspection period, the operating experience backlog was reduced to about 95 items. The rnajor contributor to this reduction was the implementation of graded reviews of Millstone LERs per NOOP 3.04.
c. Cnnclusions The Unit 2 NSEG is responsible for performing ISEG and OE reviews, although the ISEG function is not a regulatory requirement. An increase in the OE review backlog was due mainly to a large increase in the generation of operating experience within the nuclear industry during the first half of 1997. Staffing levels in the Unit 2 NSEG vary at times due to assignment of personnel to special projects, and there have usually been vacancies within the group. Graded reviews of Millstone LERs focused resources on external nuclear experience, which helped reduce the backlog of OE items.
U2 08 MisceIInneous Operations issues 08.1 LCloand) Insocctor Followuo item 50-236/95 201 06: Numerous Problems with the Equipment Taagina. System (Related to Significant items List No. G)
a. inspsction Scope (929031 In May 1995, a restart assessment team inspection (RATI) identified numerous past problems of improperly isolated equipment, and personnel who had worked outside of established tagging boundaries. The initiating event involved the tagging of electrical equipment for maintenance. It was found that improper tagging omitted a live circuit that caused a screw driver to be shorted out during the work process. This event prompted the licensee to perform a root cause to find the reason for the errors. The RATI team reviewed the root cause that proposed adjustments to the program. The results were that: 1)
Procedure " Equipment Tagging", ACP OA 2.06A, Rev. 21, did not clearly delineate responsibilities for the establishment and verification of tagging boundaries; and 2) The procedure did not clearly describe managements expectations regardmg the responsibility for specifying, performing and verifying the appropriateness of tagging boundaries. The team also identified that self assessment, by the licensee, indicated that the operators being relied on to perform the tagging had limited knowledge and experience in the electrical area. The root cause analysis cited:
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- 19 i e personnel errors j e less than adequate work procedures !
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- e procedures not being followed procedural deficiencies
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i e j e management deficiency for setting standards and expectations ,
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I The inspector reviewed the licencee's actions since March 1995, and had discussions with-licensee operations management to assess the effectivenese of the corrective actions.
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- b. Observations and Findinas ;
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! The inspector reviewed training lesson plans and training records that showed enhanced [
training was performed for the operations work control group (those responsible for l - tagging). The training reiterated the need to be vigilant in the execution of tagging because ,
i of the serious nature of isolating and deenergizing electrical and high energy systems for !
} maintenance. Training was also conducted in the reading of electrical prints. The ;
- inspector confirmed that the key points of the training were tested to show comprehension by the people attending the training sessions. T he inspector also confirmed that the training was now being conducted annually. <
k The inspector reviewed tagging procedure WC 2 (replacement for procedure ACP-QA-
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2.00Al noting that improvements were made describing the responsibilities of procedure
!- users. The procedure clearly delineated the responsibilities and accountably for the functions of tagging equipment for maintenance. The procedure also delineates the authority for the development of a clearance (the tagging of a system for maintenrince),
- who, how and when tags were hung and the condition of the equipment receiving the tag.
The inspector toured portions of the plant and the control room and observed that the tags were attached in accordance with the procedure. This included all tags being hung with a red tie-wrap. The tie wrap was instituted to insure that if a tag is inadvertently torn or
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otherwise removed from a component the next person who attempts to operate the equipment would know a tag should be there. Caution would be warranted to operate the ;
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component.- The removal of tags following maintenance was also discussed in the procedure.
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- The inspector reviewed the latest self assessment conducted in July 1997 and the previous assessment conducted April 1997. The inspector noted that the assessments were critical
]i and identified a variety of errors. Yearly about 10,000 tags are hung at Unit 2, so f ar in 1997 six eirors were identified. This is down from 19 errors in 1990. Errors were categorized into tagging errors and mispositioning errors. The tagging errors, mostly paperwork glitches, appear to be decreasing, however, mispositioning errors were still
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unacceptable to the licensee. The_ inspector verified that this finding was being addressed
- in shif t briefings and training ENsions.
L As a result of the self assessments, the licensee made improvements to the tagging
. system. Some examples follow: In 1996, the assessment identified problems occurring during the clearance development. The problems were not being identified during the
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subsequent review and authorization by the work control senior reactor operators (SRO's).
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This trend was presented to operations personnel during control room briefings and was added to the training program. Af ter this initiative, the inspector noted that no errors occurred for a period of six months. Another example in 1997 indicated that common cause analysis showed complacency as a causal factor for tagging errors. Operations discussed this with tagging personnel and SRO's. The frequency of self assessment was increased. The inspector noted that this typs of error has decreased. Operations Department current focus is in the area of mispositioning of the equipment, which was discussed at shift briefings and training,
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Licensee self-assessments have also led to improvements in the tagging procedure. The inspector confirmed changes were made as the result of self assessment. When a self-assessment process identified a problem, a corrective action was written to correct it. The inspector reviewed several corrective action reports and confirmed that changes were made to the tagging procedure, which include the following: (1) CR 96 0785 improved the
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way leads for breakers, that were removed from lighting cabinets, were tagged. The change also improved the way tags were attached to the cabinets. These changes increased safety because it is now uniform and all tags are attached in the same manner; (2) CH 97 0967 caused a new maintenance procedure to be created on how to install gagging devices (a device installed to prevent operation of a valve for testing purposes).
The tagging procedure was also changed to reference the procedure for gagging when required; and (3) Corrective actions have also led to the clarification of the way blue tags are to be used during the performance of testing after maintenance, an area of self-identified recurring problems.
c. Conclusions The inspector considers this item closed based on the following: 1) The procedure for conducting a clearance was improved in the areas of who is responsible, how the tasks are to be accomplished, emphasis on verification, and highlighted steps to prompt the user on his/her responsibilities; (2) The licensee has an ongoing self assessment that prompts further enhancements to the program; and 3) Training is conducted yearly with subjects ginaned from the self assessmentt. Unit 2 has shown improvements for conducting clearances as a result of their self assessment program. Although this item is not specifically referenced, it is one element that will be u ed in evaluating Significant items List 6, * Work Control".
08.2 LCksed) Violation 50-336/97-02-13: Inadeauste Corrective Action to Address lhe Sinale Failure of Damoer AC-11 a. IDECC11on Scooe (92901)
The inspector reviewed the corrective actions implemented in response to the subject Notice of Violation.
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b. Observations and Findinos This violation was issued whon Unit 2 failed to adequately identify and correct a deficiency ,
with an alarm response procedure (ARP). Procedure ARP 2590H, " Alarm Response for ,
Control Room Radiation Monitor Panels," RC 14. " Unit 2 Stack Gaseous," was written !
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such that it may have delayed the main oxhaust fans from being secured if a single failure of damper AC 11 were to occur during purgine operations concurrent with a loss of coolant '
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accident (LOCA). It may have been possible to exceed 10 CFR 100 limits for offsite dose following a LOCA.
The licensee's corrective actic'n consisted of revising procedure ARP 2590H to direct
- operators to secN all main exhaust fans when a high stack radiation monitor alarm is !
received coincidet.i with a LOCA. The inspector reviewed Revision 2 of ARP 2590H and noted that the procedure now directs the operator to stop all main exhaust f ans if a LOCA ,
has been diagnosed and the stack gas high radiation monitor alarms. ,
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c. Conclusions The licensee's corrective actions were appropriate and had been implemented to resolve this issue. The broader issue regarding the effectiveness of the corrective action program, is considered an NRC restart issue and will be the subject of future NRC inspection activity.
This item is closed.
U2.ll Maintenance U2 M1 Conduct of Maintenance M 1.1 laadvertent Start of the "A" Emerogncv Diesel Generator while IJoubleshooting On August 2,1997, while troubleshooting the cause of a blown fuse in engineered safeguards actuation system (ESAS) cabinet number 5, the "A" emergency diesel qenerator inadvertently started due to inadequate instructions in the troubleshooting plan.
, Licensee Event Report 50 336/97 27, which discusses this event, will be reviewed in a future NRC inspection report following licensee completion of necessary corrective actions.
U2 M3 - Maintenance Procedures and Documentation M 3.1 Incorooration of Vendor Technical Manualinformation into Emergencv DiesgLGenerator Maintenance Procedure a. Insoection Scone (62700)
This' inspector reviewed procedure MP 2719A, " Emergency Diesel Generator Overhaul,"
and evaluated whether the licensee had incorporated relevant information from the Fairbanks Morse Technical Manual.
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b. Observations and Findinas '
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Specifically, the inspector reviewed whether the torque requirements associated with the
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main bearing and connecting rod caps that are specified in procedure MP 2719A are i consistent with the vendor manual. If the torque values specified in procedure 2719 were ,
a found to be higher, this could cause the bearing tu become distorted and could have ;
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possibly contributed to the f ailure of the "B" emergency diesel generator (EDG) on April 17,
- 1996.
The vendor manual specifies the following torque limits: .
(a) Connecting Rod Bolt Nuts 175 200 Foot pounds
, (b) Main Bearing Bolt Nuts 700 1000 Foot pounds :
These toraue limits are unchanged since date of manufacture for the "B" EDO. The <
4 inspector verified that procedure MP 2719A had correctly incorporated these torque limits. :
. Further, the mechanics annotated on Automated Work Order M2 96 01172 that bearings .r l were installed per procedure MP 2719A.
I c. Conclusion The inspector found no evidence that either the "B" EDG main bearing or connecting rod bearing assemblies were torqued to a value higher than specified by the manufacturer.
U2 M8 Miscellaneous Maintenance issues -
M8.1 (Ocen) Escalated Enforcement item 50 336/96-08-08: Corrective Actions Associated with Surveillances that Perform Valve Position Lineuns (Closed -
Significant items List No. 35)
! a. Insoection Scoce (92902)
i The inspector reviewed the corrective actions taken in response to the subje::t escalated enforcement item.
j b. Observations and Findinas
} This item described the licensee's f ailure to implement a corrective action identified in
! Licensee Event Report (LER) 50 336/96 023. LER 96-023 was written when the licensee ditcovered that several containment isolation valves did not receive a monthly verification to ensure they were in the closed position as required by Technical Specification (TS). LER 96 023 stated that other TS surveillances containing requirements to verify valve positions were bein0 reviewed to identify any valves that were potentially not included within appropriate surve:llance procedures. The corrective action tracking system item that was generated to track this LER commitment indicated that the review was complete.
However, the NRC found that the review had not been performed.
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The licensee's corrective action consisted of reviewing the Unit 2 TS to determine which [
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surveillance requirements need periodic valve position checks. Associated drawings were I then reviewed to determine whether the valve lineup included all necessary valves. The 4 licensee reviewed a total of 16 valve lineups and identified problems with 13, A total of '
67 small vent, drain, instrument root and process flow valves were missing from these 13 system lineups. All of the lineups with discrepancWs were revised to include the missing i j valves.-
The inspector selected several system lineups and verified that the missing valves had been included in revisions. The inspector also noted that the licensee submitted Revision 1 to LER 96 023, which included the findings from thelt review, and also contained a new I commitment to review other surveillance procedures to ensure complisnce with TS. The e review willinitially focus on surveillance procedures required for Mode 6, and will expand to review surveillance procedures required for other mode changes. 9 I
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c. Conclusions i Completion of the commitment from LER 96 023 was found to be acceptable. The broader t- issue regarding the effectiveness of the corrective action program, including the commitment tracking process, is considered an NRC restart issue and will be the subject of
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future NRC inspection activity. The proposed violation and potential escalated enforcement
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action for this item is still under review by the NRC.
U2.lli Engineering
, U2 El Conduct of Engineering E1.1 Weld Failure on "A" Emergencv Diesel Generator Lube Oil Pioina a. Inspection Scone (93702)
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The scope of this inspection involved a review of the lube oil piping weld failure on the "A" emergency diesel generator (EDG).
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b. Observations and FindiD91 On August 2,1997, the "A" emergency diesel generator was rendered inoperable due to a f ailed weld joint on the 41/2 inch diameter discharge tubing of the motor driven lube oil
. pump which resulted in the spill of 5 to 7 gallons of tube oil before the diesel was secured.
The f ailed weld was found to have a 3 inch circumferential crack that failed due to
, ., ration induced f atigue. In addition, the f ailed weld, as well as many other welds on the skid mounted piping for both the "A" and "B" EDG, were found to be partial penetration welds (% to 2/3 of piping thickness), not full penetration welds as specified by the EDG q vendor. The licensee's evaluation showed that the piping with partial penetration welds have stresses within code allowable, but portions which were exposed to excessive
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vibration were suseptable to failure by vibration induced fatigue.
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i 24 j The licensee found that the vibration levels on the "B" EDG to be less than the "A" EDO. !
The licensee determined that based on the review of the vibration data, inspections of the
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available pipe welds and successful code stress analysis, failure of the "B" EDG skid j mounted piping ,;olncident with the "A" EDG was not considered credible. ;
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As corrective actions, the licensee is reworking and restoring all partial penetration welds to code acceptable full penetration welds prior to Mode 4. This work has been completed
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on the "B" EDO. l
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c. - Conclusion
License Event Report (LER) 50 330/97 30 describes this event and proposed corrective ;
! actions. The licensee's plans to rework and establish full penetration welds for the "A"
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and "B" EDG were found acceptable. LER 97 30 will be reviewed in a future NRC ;
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inspection report following licensee completion of necessary corrective actions.
U2 E8 Miscellaneous Engineering issues i E8.1 (Ocen) Unresolved item 50-336/96 06 08: Lack of Root _Cause Analvsis for the Damaoed Snubber Suonort of the Shutdown Coofino System (Update .
- Significant items List Nos. 8 and 25) ;
i s. Insoection Scoce (92903)
The inspector reviewei the licensee's status on the preparation of a root cause analysis to determine the triggering mechanism of the force that bent the extension ploco of the i~ snubber in the shutdown cooling system.
b. Observations and Findinan
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On May 14,1995, with the plant shutdown, hydraulic snubber support assembly No. !
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. 402009 on the shutdown cooling system was found with the rod on the extension piece of
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the snubber bent to the extent that it may have impaired operability of the snubber's support assembly. The results of the snubber functional test indicated that the snubber was operable in its as found condition, but the snubber support assembly was considered inoperable due to the bent extension piece rod. The extension piece was replaced, and the snubber was restored to its original design condition.
To assist in the evaluation of inoperable snubber support assembly No. 402009 and to determine the extent of the condition, nearby mechanical snubber No. 402008 was
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functionally tested. This snubber failed the functional test. An evaluation of the snubber identified internal failure of the snubber's components, suggesting that the source of f ailure was a fluid system transient resulting in a water hammer event. The mechanical snubber for support assembly No. 402008 was replaced following the functional test failure. To address these issues, the licensee prepared Licensee Event Report (LER)95-019 02 with a '
list of corrective actions.
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l The inspector reviewed these corrective actions, and noted that the licensee completed an engineering walkdown of the refueling water storage tank (RWST) piping. During the walkdown, the licensee identified damage to supports and piping from the RWST connections to the inlets to the low pressure safety injection (LPSI), high pressure safety ,
injection (HPSI) and containment spray pumps, and included the portion of shutdown j cooling piping that contained the snubber that was the sebject of LER 9519-02.
Through interviews with engineering personnel, the inspector verified that during the ,
licensco's walkdown a series of discrepancies between the as built and the as-designed J configuration were identified. These discrepancies raised concerns regarding the licensee's '
irnplementation of NRC bulletins lEB 79 02, " Pipe Support Base Plate Designs Using j Concrete Expansion Anchor Bolts" and IEB 7914, * Seismic Analysis for As Built Safety 1 Related Piping Systems" corrective action programs, in terms of root cause determination, j the inspector verified that the licensee is taking proper steps toward the completion of the ;
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analytical evaluation of water hammer loads. The licensee's analytical evaluation of water hammer loads has involved the following two activities:
(a) Development of two water hammer forcing functions, (one prior to and the other af ter revising the operational procedures)
(b) Analytical application of these forcing functions to piping system structural models in order to establish pipe and support reactions induced by the two water hammer scenarios.
The licensee completed the development of the forcing functions (activity a), and for activity (b) the licenseo stated the calculations are complete and are currently being reviewed by design engineering, in terms of schedule, the licensee plans to have all calculations reviewed and approved, including the associated physical work to repair damaged supports by the end of August.
c. CDndu119ns i
The inspector concluded that the licensee is taking adequate steps and progress is acceptable. However, URI 336/96-06-08 will remain open pending the NRC review of all the corrective actions required to close LER 95 019 02.
While reviewing the corrective actions listed on licensee event report (LER) No. 95 019-02, the inspector noted that corrective action No.8 calls for evaluation of the results of the implementation of NRC Bulletins IEB 79 02 and 7914. Based on discrepancies identified during the licensee's walkdown of the shutdown cooling systems, the adequacy of corrective actions taken in response to lEB 79-02 and 7914 is in question. This is considered unresolved pending the NRC review of the licensco's self assessment of this issue. (URI 50 336/97 203 05)
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E8.2 (Closedl UAl 50 336/96 0610 & (Undate) eel 50 336/96 06-11; Containment Sumo Screen Mesh Had Holes Laroer Tha_n_Deslaned (Closed Significant item List No. 22)
a. Insoection Scone (92903)
As documented in NRC Inspection Report 50 336/96 06, issues were addressed concerning identified problems with the emergency core cooling system (ECCS). The licensee discovered, during the review of industry operating experience data, that the screen mesh design size (0.187 X 0.187 inches) for two end panels of the ECCS sump area was larger 1 (0.250 inch with the center portion having a 0.375 inch gap) and could pass materials ;
larger than the throttled opening of the high pressure safety injection (HPSI) throttle valves.
The licensee was unsuccessfulin justifying continued operation. In February 1996, the unit was shutdown and a containment inspection revealed ten openings in the existing
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- screen housing, one as large as 0.25 inches by two feet. The licensee replaced the entire screened ECCS sump housing with one consistent with the original design. The inspector reviewed the design change (DCR M2 69 020A) including it's implementation to evaluate <
the resolution of the oversized openings.
b. Observations and Findinos Although not required by DE2 96109, " Emergency Core Cooling System (ECCS) Design Basis Evaluation / Operability Determinction for Potential Clogging of the HPCIInjection Valves." dated March 22,1996, the mesh screen was changed from 0.187 X 0.187 inches to 0.094 X 0.094 inches. The inspector reviewed analysis 960201367 M1 that was !
performed for the new screen size. The analysis assumed a full double ended break of the reactor coolant system which is considered the break that will deliver the most debris to the sump area. The analysis also assumed a solid top verses the old screen top. By review of the calculation the inspector noted that the majority of the water flowing into the sump area contains three types of debris. The first is heavier than water and will sink to the -
bottom of containment. Most of this debris will be large enough to be filtered out by the grating and the screen (0.094 X 0.094 inches). The rest should not enter the systems because the suction is through a stand pipe that is eleven inches from the floor and velocity is in the area of 0.305 feet per second. The second is lighter than the water and will float on the surf ace of the water and will experience the same screening as the first, except the debris will float on the surface and not enter the stand pipes. The third is neutrally buoyant and will experience the same filtration as one and two, however, it can enter the system. The debris, mostly sof t, then goes through seven stages of the high pressure injection pump where it is pulverized. The calculation shows that the screens will not clog to such a degree that the flow to the standpipes will be starved of the necessary flow to accommodate the core cooling required by design. -
The inspector confirmed that containment spray nozzles have 0.375 inch orifices. Licensee correspondence with the spray pump vendor confirmed that the containment spray system pumps can pass particles up to 0,532 inches. The seal manuf acturer for the pumps confirmed, via letter, that the fibrous debris postulated would not cause the seal to
. catastrophically fail or cause the pump to fail. The inspector observed that the high
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pressure safety injection valves, used for throttling will pass the largest debris that get through the sump screens in their throttled position.
The inspector noted that the sump system features and location did not change; however, the er' closure was made stronger by the addition of a solid stainless top rather than a mesh top and the screen mesh was of a smaller size. The entire structure was designed to QA CAT 1 and was constructed of stainless steel with the exception of the galvanized grating in front of the screers area. The screen mesh covers with all four sides having the mesh size of 0.094 X 0.094 inches. The inspector walked down the sump area and verified that all contact areas and fits around the "l" beams were scaled with a continuous bead of RTV adhesive / sealant (OA CAT 1 approved) as required by design. The inspector also verified that no openings appeared to be greater than the size of the screen mesh. The inspector considered the structure built to the design specifications and did not identify any areas of concern.
The licensee concluded that the problems with the initial installation were attributable to a construction installation error resulting from inadequate administrative controls and inadequate management expectations for reporting and correction of degraded or non conforming conditions. The licensee was addressing administrative controls through the issuance and revision of the design control manual. The licensee is also performing a review of the stations' design basis design process and programs related to design.
The inspector verified that the licensee used the new design change process to design and construct the new sump area. The inspector did not find any problems during the re"isw of the design change or the installation of the ECCS sump screen. Appropriate changes were made to section 6.2 of the FSAR: Technical Specifications do not require a change; and, the changes to the sump area were updated in the design basis to reflect the current changes, c. Conclusions Based on the above, the inspector considers the sump area reconstructed in a manner to prevent the introduction of debris larger than that which could cause damage to components or prevent plugging of valves and orifices in the ECCS. Unresolved item 50-336/96 0610 is considered closed. The broeder issue regarding the effectiveness of the corrective action program, including the commitment tracking process, is considered an NRC restart issue and will be the subject of future NRC inspection activity. The proposed violation and potential escalated enforcement action associated with eel 50 336/96 06 11 is still under review by the NRC.
E8.3 10oen) eel 50 336!96-06 12. Electrical Eauioment Qualification of Solenoid-Operated Valves inside Containment (Update Significant item List No.19)
a. lospection Scoce (92903)
In March 1996, the licensee identified that the environmental qualification of seven solenoid operated valves (SOVs) inside the reactor containment, could not be
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demonstrated. This deficiency was later determined by the NRC to be an apparent violation. Because vanous sources (LER, NRC inspection report, enforcement conference)
identified different corrective actions, and none of the corrective actions had been completed at the time of this inspection, the licensee gcnerated an inte0 rated corrective action plan, which combined all entrective actions into a sin 0l e list, and completed an implementation plan for each of these correctiva actions. The inspector reviewed these corrective action and implementation plans to determine their acceptability, b. Qbscrvation and Findinas On April 25,1996, the licensee issued licensee event report (LER) 50-336/9619 to report to the NRC that the qualification of seven SOVs inside the containment could not be demonstrated. These SOVs (2 ED 888,89S,91S,100S; 2 CH 517S,518S,519S) were originally thought to function as containment isolation only. An engineering review in March 1996 of the safety function requirements (SFR) for these valves revealed that these valves were required to be reopened to perform safety functions following a design basis accident (DBA) inside the reactor co*1tainment. The licensee issuco Adverse Condition Report (ACR) #7923 on March 26,1996, to document and track the resolution for this deficient condition.
There were several sources where corrective actions were discussed. In the LER, the licensee committed to ccmplete the following corrective actions prior to entering Mode 4:
- The affected SOV circuits will be modified with qualified pigtail to field cable terminations and sealing connectors.
- The EO documentation will be updated to demonstrate ful; qualification of each SOV circuit configured as required with qualified seals and terminations.
- A full review of the remtain0 SOV circuit configurations will be performed to identify whether additional deficiencies exist.
The licensee also committed, in the I.ER, to complete the following corrective actions prior to entering mode 2:
- The corrective actions associated with item 3 above will be completed.
- The SFRs for all Unit 2 EO components will be completed and reviewed for pro 0 ram impact; any deficiencies identified will be resolved.
NRC Inspection Report 96-06 documented this event and determined this deficiency to be a potential escalated enforcement item, in that inspection report, the inspector identified the following issues that need to be addressed:
- The safety functions of individual components and the duration they must perform that function had not been comprehensively and cccurately defined for the EQ Program components.
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e The licensee had determir'ed that the 1986 EQ field walkdowns were inadequate because the walkdowns were not comprehensive; the walkdowns j were performed by maintenance technicians and contractor personnel that ;
were not atlequately trained; and many concerns identified in the walkdowns !
were not adequatoly dispositioned As a result, during the current shutdown, the licensee planed to complete a comprehensive walkdown of readily accessible EO equipment. !
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o The licensee determined that EQ preventive maintenance requirements had not been incorporated into the Unit 2 tracking system.
During an enforcement conference conducted in December,1996, the licensee indicated that the following corrective actions had been planned to prevent recurrence:
- The SFRs for all EO components would be completed and reviewed and the resulting discrepancies resolved.
e The affected SOV circuits will be modified with environmentally qualified seals and qualified pigtall to field cable terminations.
- A full review of the remaining SOV circuit configurations will be performed to identify and resolve any qualification deficiencies.
- Address management issues by implementing the Operational Readinebs Plan.
o Complete EQ program assessment corrective actions by implementing the Operational Readiness Plan.
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The licensee evaluated the corrective actions from various sources as discussed above, and generated an *NRC Closure Package" for eel 50 336/96 06 12. This package contained a unified list for all corrective actions, ..,d the implementation plan for these actions. The inspector reviewed the documents contained in this package and found the implementation plan genertJly acceptable. However, there were two items that were not discussed in the plan, aid the licensee agreed to included them into their next revision: 1) a full review of all SOV circuits inside the containment, the licensee would assign a task for this review; and 2) for the not readily accessible EO equipment that was not walked down, a touwugh review of the design records would be performed to ensure the equipment's environmental-qualification. The inspector determined that this item could be closed after NRC verification of completion of the following six corrective actions:
- - Design change request DCR M2 96 96063, which would modify the electrical connections for seven affected SOVs (scheduled for implementation on October 15,1997, using AIR 96004075 05) (LER 50 336/96-019).
e Updated equipment qualification records (EORs) for the seven SOV circuit ccnfigurations with qualified terminations and seals (expected for completion l
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on November 7,1997, using A/R 96004075 06 and .09) (LER 50 336/96 019). l
e Safety function requirements (SFRs) for all electrical equipment qualification .
components, using A/R 96004075-00 (IR 50 336/96 06). .
I e A full review of the SFRs for all SOV circuits both inside and outside the
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containment and the resolution of resulting deficiencies. A/R 96004075 07
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! was issued for SOV circuits outside the contalnment. The licensee stated that i another task number would be assigned for SOV circuits inside the containment (Enforcement conference commitment). [
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e A more comprehensive walkdown of all accessible EQ equipmsnt. The !
licensee stated that about 80% of all EQ equipment were accessible. The licensee also stated that for the inaccessible EQ equipmr u, a thorough review of design records would be performed to ensure the equipment's environmental qualification (IR 50 336/96 06). -
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e implementation nf Operational Readiness Plan which would address e
management issues and complete EQ program assessment corrective actions as discussed in the enforcement conference.
c. Conclusions in March 1996, the licensee identified that seven SOVs inside the reactor containment
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were found not environmentally qualified. This deficiency was later determined by the NRC i to be an apparent violation. The licensee had complated an extensive evaluat!on tc, determine the appropriate corrective actions and implementation plans for these corrective actions. The inspector concluded that these corrective actions and implementation plans were generally acceptable, with the addition of two sub tasks as described above. TI.is item remains open pending NRC verification of licensee's completion of six corrective actions listed in section (b) above.
This item was part of the Unit 2 EQ program that needs to be reviewed by the NRC before Unit 2 restart. The overall Unit 2 EQ program was not ready for review at the time of the
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inspection.
E8.4 {Quen) eel 50-336/96 201 11 and EElitem 50-336/96-201 31: Failure to Moguatelv _ Control Installation Modificallon to the RBCCW Surge Tank
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(Update . Significant item List No. 28)
a. 'nsoection Scoce (922031 The intpector reviewed the corrective actions taken to address the inadequacies in the design, installation and inspection of a modification of the reactor building closed cooling water (RBCCW) surge tank and in the procedures that control temporary modifications as identified in NRC team inspection 50 336/96 201, i
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b. Observation'and Findings NRC Inspection Report 96 201 includes a discussion of a concern with a temporary modification of the RBCCW surge tank. The modification involved wood components, .
"come alongs", a nylen eling and several metal cable rigging slings. The modification had been processed and installed in accordance with bypass jumper (B/J) 2 95-045 and was necessary to resolve tank operability concerns regarding the seismic design adequacy of the tank. Inspectors noted various deficiencies in the installation associated with the come alongs and wood components. Review of the temporary modification B/J design package showed that the installed configuration did not conform with the design document and that these discrepancies were not identified during walkdown inspections. Further, installation modifications made at later dates were not reviewed in any documented design evaluation.
The f ailure to establish controls to ensure that a temporary modification wris installed in accordance with the approved design document and that subsequent changes were subject to quality design control measures was considered an apparent violation of 10CFR50, Appendix B, Design Control. (eel 50 336/96 201 11)
Af ter noting the deficiencies in the installed configuration the inspection team reviewed Calculation 95.ENG 1198 M2, Revision 1, which was used for the design and analysis of both the temporary and final modification of the tank. The team identified five deficiencies and determined the design verification of the calculation to be inadequate. The licensee lasued Revision 2 of the calculation to address the deficiencies noted. The inspection team
. reviewed the revision and concluded that the design verification continued to be inadequate i
because of six additional deficiencies. This fallure to verify the adequacy of the design was considered an apparent violation of 10CFR50, Appendix B, Design Control. (eel 50-
! 336/96 201 31)
Adverse Condition Report (ACR) M2 96-0465 was issued to document the design control
- f ailures identified in Escalated Enforcement items (Eels) 336/96-201 11 and 336/96 201-31. The licensee included the subject Eels in the Common Cause Assessment of Apparent 4 Violations, dated December 13,1996, that it prepared in response to the many apparent I violations identified by the NRC. ACR 7965 was also issued to track and trend an error in the design calculation and ACR's 10214 and 10651 to address deficiencies associated
- with the come alongs, es identified by the inspection team.
The causes cited for the design control deficiencies were inadequate management expectations, inadequate work oversight and control, and inadequate engineering design
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and configuration control. Corrective actions to address the surge tank specific issues and to improve the design control process for both temporary and final modifications were undertaken. Regarding the tank specific issues, calculation 95-ENG 1198 M2 was revised J to address the deficiencies noted and the associated final modifications were installed.
The inspector determined that the issues raised by the inspection team regarding Revision 2 Calculation 95 ENG 1198 M2 had been addressed and/or resolved in the new revision.
However the inspector noted other deficiencies in the calculation and concluded it did not verify the design adequacy of the modified tank support system. Specifically, the inspector
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found that the assumption of equalload sharing between the upper and lower wire rope
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supports was not substantiated and was not correct Given that, and sinca the wire ropes were loaded to 99% of their allowable inad, any unequal distribution of the load could !'
result in an overload condition.
The inspector discussed the calculation with a licenseo design engineer. The engineer stated that the calculation had been the subject of a recent informal review. That review was prompted by the observation of a team rnember of the Electrical Equipment Qualification & Seismic Qualification Program nuclear oversite audit team (audit conducted in May 12 23,1997) who commented that on the basis of Industry experienco design problems were encountered when wife ropes were used to restrain components. The informal review revealed deficiencies, including the one stated above, in the design calculation. The licensoo issued CR M2 971803 to document the concerns and to implement and track the additional design activities necessary to achieve and demonstra'e design adequacy of the RBCCW surge tank seismic restraints.
An inspection of the RBCCW tank and the adjacent tornado missile shield was performed.
The permanent modification of the surge tank seismic restraint system was seen to be installed and appeared to be consistent with the design calculation package. No deficiencies in the Installation were noted.
To improve the design control process a Unit 2 design engineer training manual wat; issued and a formal engineer training program was instituted. Unit 2 maintenance personnel and supervisors were given training in the use of lif ting and rigging equipment and the Millstone lif ting and Handling Manual was issued, Issue specific training was given to allindividuals involved with the design modification, implementation and inspection of the surge tank, and a change was mado in the bypass jumper work control prucedure (WC 10). Broader licensee initiatives to improve the design control process include outlining management expectations in the Operations Headiness Plan (;n preparation), t,nd in a policy report titled Nuclear Stnndards and Expectations, and revision of the Design Control Manual (DCM).
The inspector reviewed the revisions to the Design Control Manual and the modification to the work control procedure WC 10. It was observed that the majority of the changes in the DCM could be catcgorized as either providing clarification to the text or stating additional requirements. As such, they should provide improvement to the design process, The manual, however, does not specifically address the bypass jumper (B/J) or temporary modification process and therefore may have little direct impact on that process. Work control procedure WC 10, on the other hand, does control the temporary modification process. This procedure now includes requirements that,if a written technical evaluation is required to support the modification, design input checks and a design verification must be performed in accordance with Chapter 4 of the DCM, and if a safety evaluation is required, it must be performed in accordance with Nuclear Group Procedure 3.12. These requirements raise the standard of technical and safety evaluationc for temporary modihcations.
The inspector reviewed the design engineering training materials and the rigging and lif ting training materials. Both sets of material seem appropriate for their purpose.. The engineer training program appears comprehensive and should allow a realistic assessment of each
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L designer engineer's capabilities, it encompasses training at alllevels up to department .
- manager and includes a statement of management expectations and job / plant / site specific !
training including governing laws and standards for each classification. The included !
i completion check list uses recognized design control f ailures (eel's, CR's, LER's) to i
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emphasire design attributen.
i j c. Conclusiong l
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i The revisions made to the Design Control Manual and to the work control procedure WC 10 '
are considered positive, and should improve the design control process. The fact that the !
- DCM does not specifically address the temporary modification design process, however, is !
[ considered a weakness. Inclusion of this process in the DCM would strengthen recognition that the temporary modification process is a quality design activity and requires design practices commensurate with that classification.
The newly instituted design engineer training program is also considered positive it should
provide the means to convey to the engineering staff their expected level of knowledge and !
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management expectations in that regard. As a minimum, it should allow a clear !
classification of the capabilities of each engineur and a matching of talents to job
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requirements. The assignment of personnel with the proper capabilities to given design
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activities should improve the design process. Regarding the rigging and lif ting training material, it is considered comprehensive.
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Af ter completing the permanent modifications to address seismic concerns associated w!th the RBCCW surge tank, the NRC found the design calculation was inadequate due to incorrect assumptions regarding the use of wire rope supports that were installed.
!- Discussions with the licensee indicated they were already aware of the inadequacy due to i a Nuclear Oversite audit team identifying the same concern reflecting positively on Nuclear Oversight performance, but negatively on design engineenng performance. The licensee la in the process of revising this calculation.
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The license.s has taken definite corrective measures to improve the deaign contro', process. ;
1 Although these actions are considered positive and should improve the design control process. Eels 50 336/96 201 11 and 50 336/96 20131 remain open pending NRC considerations of potential escalated enforcement action involving these issues and
completion of the RBCCW surge tank modifications, p
E8.5 - [Qoen) eel 50 31_6/96 201 12! Failure to Establish and Maintain Measureand
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Qasign Controls to Maintain Deslan Basis for the Wide Ranae Nuclear -
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instrumentation Channels (Closed Significant item List No. 29) !
i a.- Insocction Scoce (92903)
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The scope of this inspection included a review of Escalated Enforcement item (EEI) 60- ,
I 336/96 201 12. Adverse Condition Report (ACR) 8001 identified a common mode failure of wide range (WR) nuclear instrumentation (NI) channels "B" and "C", in addition, ,
Licensee Event Report (LER) 96 013 00 describes a design configuration of the installed .
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annunciator alarm circuit that created a common path to all four WR NI channels which j
. Introduced electrical noise signets to other redundant WR drawers. The inspector reviewed j the licensee's corrective actions to address the concern. l
I b. Qhervations and Findinas I
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Subsequent to discovery of the potential vulnerability of WR Nl channels A, B, C, and D to a common mode failure, three engineering reviews were performed independently to evaluate the safety impact of electrical noise signal propagation through the common
= annunciator circuit for the NI channels (Reference Engineering Record ER 90-0064, Rev.1).
The review performed by ABB Combustion Engineering (CE) indicated that the coll to- l'
contact isolation in the Reactor Protection System (RPS) Interface with the annunciator I
. circuit reduces the likelihood of interactions between channels. The CE review concluded that, although the WR instrumentation channels can be sensitive to high levels of external ;
electromagnetic interference (EMI) signals, the WR instrumentation design would not i prevent a valid RPS trip signal. As shown on Engineering Drawing 25203 29198 Sheet 3, the inspector noted that the " daisy chain" connection of relay contact outputs in the wiring ;
logic will not inhibit any RPS trip actuation signals. The two other engineering revwws
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concluded that the removal of the annunciator circuit connections would remove the
. potential for electrical noise signals generated in that circuit to be propagated to the Ni system.
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Based on a field walkdown, the inspector noted that a temporary bypass jumper (#2 96-
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027) had been installed on the Nl annunciator circuit to eliminate busceptibility to common
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- mode failure of NI channels. This temporary modification resulted in the disabling of the
"NIS Channel Inoperative" annundator. However, the licensee had established temporary 1 guidance for Operations personnu to monitor the WR Ni channels while the annunciator
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remained inoperable.
The licensee's planned approach for resolution of the potential common mode f ailure of WR NI channels (reference Engineering Record ER 96 0117, May 14,1996) included the following actions:
(1) Perform testo to accomplish the following:
- Re create the cross channel noise interference effects in the WR Ni drawors
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4 + Reduce the existing annunciator circuit voltage from 125 Vdc to
- 28 Vdc by installing an interposing relay circuit
- Demonstrate the lack of adverse cross channelinterference- *
elfects in WR Ni channels with a 28 Vdc arrangement for the
annunciator circuit
- Demonstrate the operability of all Ni linear range trip functions with a 28 Vdc arrangement for the annunciator circuit t
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2) Install the tested 28 Vdc modification in all nine annunciator circuits which are common to the WR and linear range NI rocks DCR # M2 96056, Revision 0, "NI Annunciator Circuits Modification," was initiated for modification of the NI channel circuit, and this was approved by PORC on May 21,1997.
Under AWO # MbO7 00438, the licensee performed Special Procedure SPROC 96 2 3, Revia.on 1, Chan0e 1, "RPS No;se issues Spocial Procedure (IPTE)," to veilly RPS noise testing methods, ud to determine the effectiveness of the proposed design changes for signal noise reduvtic,.) in tha Ni channel circuit. The completed test results indicated that a .
28 Vdc arrangement minimized the signal noise effects.
Based on a field walkdunn, the inspector verified that nine interposing relays are installed in the nonvitallnon OA annunciator circuits in rack 5 of Annunciator Cabinet RC22, per DCN DM2-00 0114 97, to reduce circuit voltage from 125 Vdc to 28Vdc. It was noted that those relays were Potter & Brumfield KRP 11DG relays. The inspector found that NRC Information N :tice 9219 concerning misapplication of Potter Brumfield MDR and rotary reiays were not addressed in the DCR. However, the issue of contact rating and contact loading discussed in NRC IN 9219 was addressed in the DCR. The KRP 11DG relay was
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used in the conceptual design proof insts in which the relay was cycled at least a few thou. sand times, and no dama0e was observed af ter test. As a followup to the inspection, the licensee evaluated the applicability issue through correspondence and discussion with a Potter and Brumfield representative. TI e correspondence indicated that the contact rating, contact loading, and voltage rating of KRP 11DG relays were acenptable for the application specified in the DCR.
An FSAR cnange rcquest was initiated to include additionalinformation in the FSAR description to reflect the installation of interposing re!ays in the Ni annunciator circuits.
The inspe : tor reviewed this inicrmation and found the revised description to be satisfactory, c. Conclusions Licensee corrective actions to address specific concerns in eel 50-336/96 201 12 related to si0nal noise ef fects in the N1 ann nciator circuits wers. determined to be acceptable.
The broader issue regarding folluie of the limwee to establit.h and nisintain measures and design controls to .nalntain design basis for the WR NI channels is a NRC restart issue.
The considerations of escalated enforcement action for this issue are still under review by the NRC.
E8.6 iOcen) eel 50-336/96-20.1-28: Failure to Address the Station Blackout ligues lderitified in the Vectra m;siment (Updaty Significant items I.ist No. 31)
a. Inspection Scooe (92903)
The scope of this inspection included a review of eel 50 336/96-201 28. Adverse Condition Repod (ACR) 11097 documented the f ailure to address Station Blackout (SBO)
issues identified in a vendor's (VECTRA) assessment. Thirteen Unresolved item Reports
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(UIRs) havr. been issued to discuss the details and recommended disposition of each identified SBO issue, in sddition, Action Requests (AR) have been initiated to track the progress of corrective actions and closure of the SBO issues described in the UIRs.
The mspector reviewed the licensee's currective actions to address the SBO concerns.
D. OhicIyations.and Findinas The licensee performed an engineering self assessment of the Unit 2 SBO program to determine whether compliance to the licensing basis was adequately maintained. The self-assessment (ESAR PRGM 97 028, Revision 0) identified some of the items that need to be completed prior to plant start up, and the areas where improvement in the implementation processes are needed to ensure program compliance with the licensing and design bases.
Other items included commitments made that have not been closed. An action item list covering the open items in the VECTRA assessment as well as other documentation deficiencies was summarized in the self assessment report.
One open SBO issue (VECTRA lssue 3.2.4) was the licensee's commitment to demonstrate that the MP2 Altemate AC (AAC) system is capable of powering the necessary equipment within one hour. CR M2 97 0941 identified the need for validation testing of the electrical cross tie between MP1 and MP2 as the AAC source rather than taking credit for the previous justification of not performing the test The licensee initiated a memorandum M297023 221 (dated 7/25/97) to dispoution ARs 97017467 01, and 97017467 02, for the timed validation test of transferring Electrical Bus 24E supply from Bus 24C to 24D, or transferring Bus 24E supply from Bus 24D to 24C.
On July 31,1997, MP2 Operations staff performed a walk through test of transferring Bus 24E supply from Bus 24D to Bus 24C, and energizing Bus 14H from Bus 24E. This is a dead bus transfer to align the power supply from the MP2 Emergency Diesel Generator "A'
which supplies power to Bus 24E. The plant operators performed this test evolution using Section 4.5 of Procedure OP 2343, Revision 17. The time taken to accomplish this task was about 37 minutes. The validation test included additional efforts to energize Bus 14H from MP2 ucing Section 2 of Procedure ONP 503C, Revision 8. The additional time for these efforts was about 9 minutes. Thus, the total time taken for successful alignment of emergency power supply from MP2 to MP1 was about 46 minutes. The inspector noted that the plant operator had some difficulties in racking in the circuit breakers during the test walk through because he was using safety gloves of the wrong size. The licensee indicated that more safety gloves of different sizes would be made available at the switchgear areas to allow operators to perform " breaker rack-down" operations more efficiently.
Complete results of the validation test for cross tie alignment between MP1 and MP2 during SBO conditions at MP1 are presented in Engineering Evaluation M2 EV-970058,
% sion 0, 8/26/97, it was noted that the total time of 46 minutes for successfully mtynplishing the cross tie alignment included procedural tasks which could be performed concurrently. MP1 simulator results of timed response for aliCning MP1 AC power source to MP2 were also included in the Engineering Evaluation M2-EV 970058. The time taken
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for the test evolution was about 24 minutes. The inspector noted that the margin of about 36 minutes and 14 minutes, respectively for MP1 and MP2 SBO coping requirements, were reasonable to account for variations in the skills of the plant operators performing the procedural actions under actual SBO conditions.
Since the assessment of SBO coping capability for MP2 requires that credit be taken for the Unit 1 gas turbine and emergency diesel generator, the inspector questioned the schedule for work completion o, these components. An example was the work schedule for EWR #96 0168 for toe Gas Turbine Generator Air Start Valve. The licensee stated that a committee had been established to evaluate various aspects of shared components and cross ties, including their availability, relative to the startup schedule for each unit. The inspector attended a meeting of the committee in Septsmber, and noted that plans were to ensure that the various aspects of shared equipment were properly addressed by each Millstone unit. However, specific planning for MP1 had not yet implemented this straiegy for the MP1 emergency power sources needed during an SBO event at MP2, With respect to the above-mentioned example (EWR #96 0168), the :nspector noted that t was on the deferred list for Unit 1 on the July 14,97 50.54 (f) letter. The inspector questioned the appropriateness of this deferral due to the potential for failure of aged BUNA N material used in the air start valve (see above CR M197 0836). The licensee's staff is in the process of addressing all of the identified SBO issues prior to MP2 startup.
c. Conclusjons The validation test results of accomplishing the MP1 and MP2 electrical cross tie during 500 conditions indicated that the licenseo staff can meet the SBO requirement of establishing alignment to the respective AAC sources within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The licensee is also in the process of addressing the various SBO icsues and therefore, eel 50 336/96 201 28 remains open.
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38 l Report Datalla Summarv of Unit 3 status ,
i Unit 3 remained in cold shutdown (Mode 5) status throughout the inspection period. The licensee continued to implement ur't recovery activities, while continuing to evaluate the schedule for preparedness for the conduct of NRC operational readiness inspections.
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On August-18,1997 the NRC initiated an on site team inspection of the licensee's Configuration Management Program (CMP) with respect to the charging system (CHS) and ,
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associated flow paths in an emergency core cooling system (ECCS) mode of operation.. As delineated in the NRC Confirmatory Order governing the Independent Corrective Action Verification Program (ICAVP), the licensee had previously declared 88 systems, including CHS, available for review and inspection as part of the ICAVP process. The CHS system ;
was selected for "out of scope" inspection by the NRC, in part, because it is not one of the
"in scope" systems being reviewed by the ICAVP contractori Sargent and Lundy. This inspection, concluded on-site on September 19,1997 with a public exit meeting with the licensee conducted on September 24,1997 to discuss the inspection results, which will be documented in a separate NRC inspection report. -
During the week of July 11, the NRC administered initial operator examinations fur four reactor operators and four senior reactor operators. All applicants past ed eli potions of the examinatim,s. Details of this examination are documented in NRC Inspection Report 50-423/97 04.
On August 19,1997, the Board of Trustees of Northeast Utilities announced the appointment of Mr. Michael G, Morris as Chairman, President and Chief Executive Officer.
Mr. Morris replaced Mr. Bernard M. Fox, who announced his retirement in Feoruary pending the appointment of a successor. Mr. Morris formerly held the position of President and Chief Executive Officer of Consumers Energy, a Michigan utility.
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On September 4,1997 the licensee announced the appointment of Mr. David B. Amerine to the position of Vice President, Nuclear Engineering and Support Services, effective September 8,1997. Mr. Amerine replaces Mr. Jay K. Thayer who was on loan from the Yankee Atomic Electric Company as a Recovery Officer for Engineering and Support Services. Mr. Amerine formerly was a Deputy Vice President for the Westinghouse Savannah River Company.
QLLQperations U3 01 - Conduct of Operations 01.1 General Comments (717071
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Using inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing pant operations, f
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01.2 Beview of Ooerational Control. Evaluations. and Event Followuo Activities (71707. 929011 Using inspection Procedure 71707, the inspector conducted frequent reviews of ongoing plant operations, particularly with respect to plant shutdown risk management controls. A change to the control room operator shif t rotations and work schedule, instituted by unit management to augment operations support to work control activities, was discussed with the Operations Manager. In addition to plant inspection tours and control room observations, the inspector attended plant management and outage planning meetings, reviewad operability determinations and safety evaluations affecting the status of current plant operations, and assessed the operational status of systems and equipment, based upon component inspections and followup reviews of conditions reports (CRs) and related documentation. The inspecte evaluated the following activities in detail:
- conduct of an Event Review Team (ERT) root cause investigation for a CHS valve found open, providing an unantici;,ated drain path from a reactor coolant loop to the containment sump. The inspector discussed ongoing investigation results with the ERT leader and the Unit Director. While no specific cause for the mispositioned valve was identified. the ERT did cite inadequate operations'
work practices in verifying the system configurauon prior to commencing the planned loop drain evolution.
The inspector reviewed the completed ERT Root Cause investigation repo.t, dated August 22,1997, in response to CR M3 97 2485. Prompt operator action to a containment sump alarm limited the reactor coolant leak to 50 gallons: thus, no safety concem arose from the actualloss of coolant.
However, since the unexpected leakcge was attributed to a configura: ion error, the licensee took remedial corrective actions to both assure the current proper alignment of credited shutdown risk systems and validate future configuration control of flow path changes and valve line-up manipulations.
Interim licensee corrective action also included added verification controls for all valves within a job task tagging boundary. The inspector concluded that the ERT focus on the proper use of verification and validation quality techniques in the work control process placed the croper emphasis upon this event from an operational standpoint. The inspector also noted that configuration controls will be tracked by operations management as a measurement to determine readiness for the unit restart. The NRC concurs with this initiative and will monitor the effectivenesu of these corrcctive actions to meclude future configuration trrors and similar component misalignment events.
- review of the safet ' classification and procedural use and control of a
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emergency boration flow transmitter (3CHS FT183). The inspector examined this transmitter in its field location in the auxiliary building and verified its potential use by operators in the implementation of "Immediate Boration", in accordance with abnormal operating procedure, AOP 3566 (Revision 4). In
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i i reviewing the material, equipment, and parts lisis (MF.PL) program review !
relative to the boric acid system, the inspector noted some inconsistencies !
i between the MEPL Determination MP3 CD 1005 and the Technical i j Specification (TS) requirements for operable boron injection flow paths.
i Discussions with the CHS system engineer resulted in the initiation of CR M3-97 3330 to document the concerns regarding the current QA status of 3CHS- !
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4 FT183. Additionally, the inspector indicated that the FSAR description of the emergency boration flow path did not provide sufficient detai! to determine whether the credit given specific flow paths for boron injection and core a reactivity control was consistent with either the TS or the MEPL CD 1005 downgrade of equipment. Furthermore, the inspecar questioned the potential t i status of 3CHS FT183 as a component covered by the USNRC Regulatory Guide IRG) 1.97 criteria.
Since the questions raised uy the inspector relate primarily to MEPL program
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adequacy in the area of boration component controls, this issue will be further t l evaluated with respect to SIL ltem 25 (MEPL Program), which is also
discussed in Section U3 E3.1 of this inspection report.
L i e response to the declaration of inoperability of the "B" train charging system, i based upon a stroke timing test failure of the charging pump support cooling
- system temperature control valve,3CLE*TCV378. The inspector attended l meetings and discussed with the unit management personnel the available a options for restoration of reactor coolant system (RCS) makeup and charging capabilities. ' oased upon other system unavailability (e.g., primary grade water) and elevated RCS boron concentrations relative to the refueling water
, storage tank, the licensee was limited to use of the boric acid tanks as the 2 makeup water source for the RCS.
The inspector observed lice.)see planning ano actions to restore the "A* train !
charging capability, exit the applicable TS action statements, and successfully ;
2 plan and subsequently execute an RCS boron dilution to mitigate problems that l would arise if similar conditions occ . red in the futre. Coordination between operations and reactor engineering personnel during the planning and resolution of this event were noted to be detailed and effectively communicated. !
e processing a temporary modification (3 97 049) for the re positioning of two j
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exhaust dampers in the "A" train emergar'cy diesel generator (EDG) cubicle
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emergency ventilation system. The inspector reviewed the safety evaluation,
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S3 EV 97 0365, and determined that design temperature limits affecting EDG
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operability would not be adversely allected and that consideration of damper operability during a postulated tomado event was properly analyzed.
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e fo'!owup of NRC Information Notice 9185 (Revision 1) concerns regarding
, potential f ailures of thermostatic control valves (TCVs) for the EDG Jacket
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cooling water system. Thermostatically operated temperature control valves supplied by the Robert Shaw Company are utilized in both trains of the EDG jacket water, intercoolant, and lube 3il systems. The inspector confirmed through correspondence from the EDG system engineer that specific actions taken with the installed EDG TCVs at Unit 3 appear to eliminate the cc,ncerns associated with the Robert Shaw design, as referenced in this Information Notice.
Overall, the inspector identified no unresolved safety concerns with respect to the licensee response to emerging operational events or followup to equipment problems. As identified above, the continued MEPL questions and both the operations and work control management of the plant configuration for planand evolutions are areas that merit additional management attention and will receive additionalinspection scrutiny during future inspection periods.
01.2 NRC Information Notice (IN) 97 38 "Lovel Sensina Svstem initiates Common-Mode Failure of Hich Pressure Injection Pumos" a. Insoection Scone (92903) -
The inspector reviewed the licensee's avcluation of NRC IN 97-38 for applicability to Unit 3.
b. Qhervations and Findinas NRC IN 97 38 discussed a prott *m that occurred at Oconee Unit 3 due to a lesk on the letdown storage tank (LDST) levelinstrumentation reference leg. A leak at a test connection caused the draining of the reference leg and caused the two level instruments (that share the reference leg) to indicate an erroneously high level. As a result the tank emptied causing gas binding, cavitation and subsequent damage to two of the high pressure injection pumps.
The inspector reviewed the assessment of this issue by the licensee's nuclear safety engineering group as documented in an operating experience report dated August 18, 1997. The licensee determined that the design of the levelinstrumentation for the volume control tank (VCT), which is the equivalent of the LDST, was different from the Oconee design. The Millstone Unit 3 design does not utilize a reference leg. The VCT levelis monaured by lev 61 transmitters that connect to high and low pressure taps on the tank through isolating diaphragms. With this design, leakage on the instrumentation piping or tubing connections would be replaced with water from the VCT volume and would not af feet the lovel instrumentation.
The inspector performed a field inspection of the VCT and associated levelinstrumentatior and found the installation to be consistent with the licensee's evaluation.
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. The inspector concluded that the licensee performed an appropriate evaluation of the issue i i 1. :Jressed by NRC IN 97 38. The inspector also noted that the licensee evaluation went t beyond the VCT instrumentation and included a review of other instrumentation that use reference legs (steam generator and pressurizer levelinstruments).
U3 01 Operational Status of Fac:lities and Equipment ;
O2.1 Main Steam Pressure Relief Valve Controllers (71707)
The Unit 3 FSAR describes the Main Steam Pressure Relief Valves and control circuitry.
The valves serve as backup atmospheric reliefs to the main steam safety valves. They also provide a backup cooldown function to remove heat from the primary. The valves can
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. open on a high steam generator pressure signal, as controlled by their control circuitry, or they can be operated in a manual mode by the operators. The valves themselves are safety related for pressure boundary and containment isoletion purposes, but the relievn.g :
i and cooldown aspects of the valves are nonsafety related (NSR). Thus, the control
- circuitry is also NSR. This information is documented in Unit 3 MEPL evaluation MP3 CD. .
1041, l In general, over their lifetime, the valve controls hLve operated well without significant maintenance. The Nuclear Safety Engineer!ng files of operating experience (both INPO and NRC) were reviewed for items on steam generator atmospheric reliefs and no abnormal items were identified. During the Unit 3 startup program, during transient power changes, the valves did open when they should have remained closed. As a result, a design change was made to the control circuitry. No subsequent early openings were identified in the
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records. During the recent Configuration Management Program (CMP) the licensee j reviewed the calculation for determining the setpoints of the valve controller (Calculation NSP-181 MSS). 't his received a Category C review in May 1997, since the controllers are
NSR. The CMP reviewer initially noted that the calculation methodology was unclear, but i then changed this conclusion. The inspector rev.ewed the calculation and also determined ;
it was unclear and did not completely justify its values. This was discussed with other
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licensee l&C personnel who concurred that the ca%1ation had incorrect statements and j' justifications, but that the actual values ;upeared correct in general the errors relate to statements that the integral (or reset) aw..on of the controller serves to keep the valves I
from opening prematurely, when in f act the integral action has no effect until af ter the setpoint is reached. A bias of 0.25 volts is used to ensure that the valve does not open before its setpoint is reached. The licensee stated that the calculation would be revised to correct the discrepancies.
SP 3016A.1,' Main Steam Valve Operability Tests, provides guidance for tests of the main steam system valves for the Inservice Test program. For the main steam pressure relieving valves, the procedural steps include stroking and timing the valves and verifict. tion of the valve position indication.
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If a valve failed to open as required, it coulv be placed in manual and opened by the ,
operators. The operators also can manually open the main steam pressure relief bypass l valves. If pressure did continue to increase, the main steam safety valves would open and ;
provide pressure relief protection ar.d cocidown, if the valves open early, when not l required to open, the operator would get an alarm, " main steam relief valve not closed". l The Annunciator Response Procedure (ARP), OP 3353.MBSC, Window 5 7, Rev. 3, 1 providos direction for the operator to take manual control and close either the relief valve or ;
itt, upstream block valve. The inspector noted that Step 2 of the ARP did not clearly direct the operator to close the valve after taking manual control. The licensee agreed and initiated a procedure change to add this direction if the valves open properly,5 r fail to reclose on decreasing pressure, then the operator would use the same ARP to me.nually close either the relief valves or the associated upstream block valves. In the event of a need to isolate,the valvos due to * 7 team line t'reak, a steam line isolation signal automatically shuts the valves usmg safety grade components. Near the end of the inspection period, the licensee issued CR M3 97 3248 to investigate a design question related to a postulated accident scenario involving both the 3 MSS *PV20 and 3 MSS *MOV18 valves.
With the exception of the above noted items on the calculation explanation and the ARP, no other discrepancies were identified.
U3 03 Operations Procedures and Documentation 03.1 Procedure Ungrade Program Progress (Update SIL ltem 80)
a. Insoection Scoce (92901)
This inspection was a continuation of an inspection to determine the adequacy of the licensee's procedure upgrade program (P'JF) which was initiated in 1992 to standardize procedure format for all units on site and to improve the technical adequacy of all procedures. Previous inspection was performed in this area from August 1996 through February 24,1997 and findings wv documented in NRC Inspection Report (IR) 50-423/97-01.
The PUP program is t.xring completion and should be completed prior to Unit 3 restart.
The purpose of this inspection was to determine if the PUP had met its goals and if otner processes were in place tc va;xt axisting procedure deficiencies identified af ter the completion of the PUP. In c ire di ed June 4,1992, the licensee described to the NRC its Performance Enhancement togram (PEP). Summary S ction 2.3.5 of this letter described the licensee's updated efforts to standardize and develop high quality procedures. These commitments became the PUP A separate PUP charter was developed by the licensee describing the specifics of the PUP.
Since the performance of the last PUP inspection, the licensee has completed its configuration management plan (CMP) discovery process and independent verification (i.e.,
the ICAVP) by an independent ,ontractor is in progress. A portion of the CMP is ensuring
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that procedures for the systems under review meet the design and licensing bases. In addition, self assessment and oversight processes have been established. ,
in the performance of this inspection, the inspector interviewed personnel involved in procedure upgrades, the CMP and ICAVP processes, self assessment, oversight, deficiency tracking and trending, and corrective actions, Procedures involving proce,Jurs preparation, self assessment, CMP, corrective actions and oversight were also rrewet,. as well as audits and other documents produced by the above programs.
b. Observations and Findinas in the 1992 PEP letter, the licensee made several commitments conce'ning procedure improvement, some of which are summarized below:
- Determine the structure, content and format of policies and procedures i
- Standardize policies to ensure requirements are implemented in a consistent manner
- Develop and implement a master plan to improve policies and procedures
- Develop training programs to communicate procedural requirements
- En we procedures consistently implement regulatory and company requirements
- Incorporate hunian factor improvements into procedures
- Streamline various processes
- Ensure procedures are reviewed, verified and validated to ensure quality and correctness
- Ensure procedures are developed to a predefined level of standardization Through reviews conducted during this inspection and previous reviews as documented in IR 50-423/97-01, the inspector determined that most of the commitments listed above were met. Administrative policies and procedures have been streamlined :md condardized.
A myriad of policy procedures (i.e. the tiering of procedures from corpr. rate to site to unit)
have been eliminated. All policies have been placed in site administre(ive procedures which all units are expected to follow. However, it was never intendad for the PUP to vali6ste procedures with respect to either the design or licensing basis.
Technical procedures have been standardized in fomiat and procedure implementation method. Technical procedures were upgraded by separate departments within each unit.
IR 97-0_1 noted that, "...The quality of the upgraded procedures appears to depend on the producers of the procedures and the adequacy of the performance verification and
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- 45 validation (V&V) process ratner than on any apparent process deficiency...In general, management invcivement in the upgrade process seems (to have been) minimal...There.
Iwas) heavy reliance on the procedure coordinators for each department...lDuring] the five years that the Pi1P has been in pl6ce, there had been no Quality Assurance (OA) audits of the IPUP) program itself..." .
l Two of the licensee commitments in the 1992 PUP letter stated, a part, the following: (1) i Ensure procedurer consistently implement regulatory requirements and (2) Ensure !
procedures are reviewed, verified and validated to ensure quality and correctness, !
Although not the thrust of this inspection, there is other evidence that, although the PUP program had an extensive V&V process, many procedures did not entirely meet regulatory requirements and/or were not technically correct. This has been evidenced by numerous adverse condition reports (ACRs), CRs, previous NRC inspections, charges being generated
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due to procedure performance findings, various self assessments performed in 1996 and findings of the current CMP an1 the Independent Corrective Action Verification Program (ICAVP), ,
Tne completion of the PUP does not mean the end of the need for procedure improvement a.id procedure changes, The need to change procedures is an expectation which is built into the regulatory process. However, in addiiion to the routine procedure change process the inspector verified that the following processes are ongoing to ensure procedure
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progress. As a result of CMP and ICAVP, numerous procedure deficiencies
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have been identified. These deficiencies go beyond identified licensing and
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design basis inconsistencies and also include other procedural problems, These procedure reviews should result in the correction of many safety related procedures.
- There is an ongoing self assessment program, Procedure U3 OA 11, "Self-Assessment" has been issued and is being implemented. There is an extensive self assessment plan with individual assignments which was issued September 12,1997. This plan provides for self assessments in all areas of Unit 3 activities including procedures, Several self assessments already
- performed were reviewed. As a result of this procedure, an outside contractor performed an assessment for compliance to Regulatory Guide 1.33 from August 4-17,1997. The audit was issued on August 22,1997 and the
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findings and recommendations are under review by the licensee,
- There is a program in place for tracking key performance indicators including
, proceduralissues. In addition, CRs are being tracked and trended. A recent
,- report trending CRs concerning procedural deficiencies was reviewed,
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- As noted in inspection 97 01, Nuclear Oversight (QA) is more involved in the procedural review process through audits, surveillances and OC job oversight, in addition, a separate Recovery Oversight group is providing continuous
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review of the ICAVP process. This includes review of procedures included in
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the ICAVP process. Nuclear Oversight is in the concurrence chain for many i
procedures being written.
- Engineering is independently identifying procedure problems. Personnel working in the field are encouraged to report procedure deficiencies and initiate changes as procedures are being performed. The inspector noted that approximately 40 change requests to Unit 3 operating procedures due to various reasons were generated in July and August 1997.
- The procedure biennial review process has been restructured and made more rigorous.
- Inspection 97-01 identified that the procedure basis documents did not fully docament the technical basis for many procedures. Though not a regulatory non compliance, this was considered a weakness in a licensee tool used for procedure preparation and subsequent review. Since that inspection,
,:rocedure DC 2, Attachment 2, " Creating and Maintaining Basis Information" has been extensively revised to state more explicitly what is expected to be maintained in a basis document. The licensee stated that all basis documents will be updated to the new change in DC 2. This change, if properly implemented should significantly improve the basis documents, it should be noted that the licensee plans to put configura+ ion management processes in place to maintain the quality of future procedures. Because these processes are not yet in place, they were not used in reaching any conclusions for this inspection, c. Conclusions The procedure upgrade program was successfulin meeting most of the licensee's commitments madts in their June 4,1992, letter. Unit and station p,ocedures have been standardized and made more user friendly. Administrative control processes have been streamlined with overall control at the station level. Procedure improvement is an ongoing process which does not end at the completion of the PUP process. The CMP /ICAVP should correct technical flaws in many existing procedures and ensure that Unit 3 procedures are ready for restart. The NRC is currently involved in the ICAVP process and is reviewing procedures on a sampling basis. Future NRC inspection activities, including a planned Operational Safety Team inspection, will also review procedure adequacy. Based on this inspection, the issue concerning the PUP process itself is closed. Issues with specific procedures remain open pending correction of those procedures. SIL ltem 80 is hereby updated, but remains open pending future NRC inspections which willinclude inspection of licensee orocedures on a sampling basis.
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U3 04 Operator Knowledge and Performance 04.1 RHR System Post Modification Flow Test (Update - SIL ltem 13)
a. insoection Scone (71707)
The licensee recently completed modifications on the "A" train of the residual heat removal (RHR) system to allow the RHR to continue a normal cooldown or safety grade cold shutdown upon the loss of instrument air without exceeding reactor plant component cooling system (CCP) piping design temperature limits. The inspector reviewed the post-modification test procedure, draft basis document, and training documentation; observed portions of validation testing of the post modification test procedure on the simulator; discussed the test with the system engineer; and observed "just in time' training provided to control room operators and portions of the post-modification test at the auxiliary shutdown panel (ASP).
b. Observatio'1s and Findinas The inspector observed clear communication between operations, engineering and oversight personnel during the simulator validation of IST 3 97-006, "A" Train Post Modification Flow Test. The shift technical advisor and licensed reactor operator provided valuable input to engineering during this val;dation. As a result of their input, procedural steps were rewritten for clarity, and the onsite configuration of the in-plant auxiliary shutdown panel was verified to assure procedural steps could be performed as written,
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The simulator validation utilized the procedure draft basis document, which aided the operators' understanding of the procedure steps. This validation was an important and valuable process to improve the post modification test procedure. The use of a licensed operator was valuable to this process and provided procedure clarification.
The "just-in-time" training (i.e., training given to operators on recent plant changes which affect operation in the current mode) provided to operators on the modification was thorough and outlined the design reasons for the modifications, major plant and control room changes, the purpose of the IST, and the new operating limits for the system. The additional reading material provided to shift personnel further explained the changes due to the modifications and included revised logic diagrams.
-During the performarice of Section 4.6 of the IST at the auxiliary shutdown panel, the inspector noted the operator was aware of protected train equipment in the area and advised test observers to be careful. The test was locally observed by nuciear oversight and engineering personnel. - Instrumentation and control technicians were also present to assist if problems were identified. Operators performed the evolution in accordance with -
the procedure and demonstrated a questioning attitt.de when a typographical error in the procedure was identified. A procedure change was processed before the steps were performed. The inspector observed excellent communication between the local operator and control rcom personnel. The licensee appropriately stopped the procedure and carefully returned the equipment to its original status when an indicator did not illuminate
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as expected on the ASP. The l&C personnel then reviewed relevant prints and computer, points to troubleshoot the identified discrepancy, c. Conclusions The simulator validation of the "A" train RHR post modification flow test and clear communication between participating disciplines served to improve the test procedure. The use of a licensed cperator was valuable to this process and provided procedure clarification. The verbal and written training provided to operators regarding the modifications thoroughly explained the design reasons for the modifications, control room and in plant equipment changes, and goals of the post modification test, Excellent communication and procedure adherence were observed during the post modification testing. Personnel carefully returned equipment to the as found condition to accommodate troubleshooting when a discrepancy was identified. (Note: This modification was implemented, in part, to address failure-mode concerns highlighted in SIL ltem 13. This SIL-item is hereby updated.)
U3 07' Quality Assurance in Operations 07,1 Ooerational Oversloht Activities (Update - SIL ltem 73)
The inspector continued to monitor Nuclear Oversight activities to include review of Recovery Oversight assessments performed consistent with 10 CFR 50.54(f)/ Configuration Management Program (CMP) responsibilities, evaluation of the capability to perform operating experience reviews and verification activities, verification of an active Nuclear Oversight interface with the Nuclear Safety Assessment Board, and discussion with cognizant personnel on the conduct and implementation of the Nuclear Oversight Restart Verification Plan. Specific areas of inspection review and followup are detailed below.
Indeoendent Safetv Enoineerino Grouc (ISEGl The inspector reviewed the Nuclear Safety Engineering (NSE) Group organization end staffing for Unit 3 to confirm compliance with the Technical Specification (TS) 6.2.3 requirements for function and composition. The inspector examined the qualifications of the five personnel assigned to the Unit 3 ISEG, noting that the TS delineate a requirement for only four full time personnel. The additional ISEG individual provides the licensea with a degree of flexibility in temporarily assignir'g personnel to assist the other Millstone units without violating the TS license requirements.
The inspector also reviewed a sample of records in ended to document ISEG activities
relative to TS 6.2.3.4 and the operating experience (OE)information subjected to ISEG review during a monthly cycle. The inspector notec a recen' TS revision, dated April 10.
1997, to update the report of safety evaluatione to the Vice President - Nuclear Oversight, consistent with current licensee organizational titles. NSEG goals for the reduction in the backlog of OE reviews were identified to have been developed, along with other initiatives to further manage the OE backlog and maximize NP,EG efficiency, incorporation of generic industry concerns, with potential applicability to Millst ane Station, into the Unit 3 Daily
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- Status Report was determined to be effective to highlight the importance of OE insight and.
generic communications to the station staff.
At the end of this inspection period, the ISEG was being maintained at its full personnel complement, and the OE backlog reduction effort appeared to bring the number of outstanding issues to a manageable level The inspector did note, however, that the
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backlog reduction efforts had strained other ISEG surveillance, independent v..ification, and reporting activities. Overall, the licensee was found to be in compliance with the ISEG
requirements of TS 6.2.3 Further NRC inspection efforts, directed beyond compliance to 4 effectiveness assessments, are planned for implementation during a NRC Manual Chtpter 40500 team inspection, scheduled for conduct prior to the Unit 3 startup.
Nuclear Safetv Assessment Board (NSAB)
The inspector discussed with the NSAB Chairman the status of previously documented Nuclear Review Board (NRB) concerns related to Unit 3 design and testing issues of a historical nature. The NRB, as the predecessor to the NSAB, had previously sought resolution to a number of such issues documented in design deficiency reports (DDRs), it ,
was anticipated that more recent CMP activities had verified that such DDRs had been properly dispositioned. The inspector noted that shortly before the end of this inspection period, the NSAB Chairman requested that the Vice President - Nuclear Oversight conduct and assessment to validate the adequate resolution of several historical NRB issues. This
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verification effort was viewed as a positive initiative to both assess the completeness of CMP review activities, and confirm that corrective actions for previously identified problems had been appropriately addressed.
The inspector also noted that during a NSAB meeting conducted on-site on September 24-25,1997, the ISEG Report for the second quarter 1997, prepared in accordance with TS 6.2.3.4 provisions, was submitted for review and comment. An NRC Special Projects
, Office Branch Chief observed a portion of the NSAB meeting on September 25,1997.
Nuclear Oversight Restart Verification Plan i The Nuclear Oversight Restart Verification Plan was issued in August,1997 and continues to track progress to specific assessment areas, designated as " key issues", on a weekly .
basis. The inspector periodically examined the quantitative key-issue assessments performed during this report period, noting mixed results across the 21 areas assessed.
Specifically, for the attribute of " corrective action", several areas were highlighted by Nuclear Oversight as needing improvement. While " corrective action" overall was not
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deemed to represent a significant weakness, the performance trend to date did not appear to be trending upwarc.
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Supporting this assessment was a Corrective Action review of Unit 3 CMP documents and condition reports (CRs), performed by the Recovery Oversight group during this inspection period. As a result of a review of approximately 100 documents, Recovery Oversight
~ issued nine additional CRs for incomplete / inadequate disposition of corrective actions.
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-Thus, while both the Restart Verification and Recovery Oversight review activities appear f
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to be positive efforts in demonstrating the Nuclear Oversight organization's integrated
- assessment of the Unit 3 readiness to restart, the results of such rigorous evaluations (e.g.,
corrective action) have not yet resulted in improvement. Progress in this QA/ Oversight initiative, as with the ISEG and NSAB activities discussed above, will continue to be tracked and updated by the NRC as part of SIL ltem 73.
U3 08 Miscellaneous Operations issues
08.1 (Closed) Combined VIO 50 245. 336.423/96-09-04: Failure to Submit -
Technical Soecification for Oraanizational Chanaes (Partial Closure Unit 3 SIL ltem 41)
a. Insocction Scop _c The licensee implemented several changes to the site organization of the Millstone facility via memorandum that resulted in a Technical Specification violation. The NRC determined that a comprehensive review of applicable requirements had not been performed to tupport two organizational changes as discussed in IR 50-423/96 09. The inspector reviewed the licensee's corrective actions to determine if changes were made to prevent recurrence, b. Observations and Findinas The licensee responded to the violation on April 4,1997, and did not dispute the finding.
The root cause was determined to be, " Management expectations for onsite and offsite organization changes were not established." Other causes were inadequate communication within the organization, inadequate attention to emerging problems, and an inadequate accountability system. The inspector reviewed a memorandum, dated January 21,1997, from the President and Chief Executive Officer that specified the manner in which changes to the organization should be supported and documented, The memorandum also required that: Each organizational change requiring a license amendment should be evaluated in writing relative to regulatory requirements [10 CFR 50.54 (a), (p), and (q)); the evaluation ba part of any organizational change recommendation; and a safety evaluation should also be prepared to meet the current expectations of the Nuclear Safety Review Board.
The inspector reviewed a proposed TS change that was submitted to the NRC February 3, 1997, requesting the TS be revised to reflect the latest organization of Northeast Nuclear Energy Campany (NNECO). The inspector verified that the regulatory requirements listed -
above were satisfied, and that a safety evaluation was performed. Based on discussions with the Station Administrative Procedure Group (SAPG); the inspector determined that the plant licensing group ar.d SAPG were working to generate a process to control and manage organizational changes, and that the memorandum discussed above would be the basis for future changes. The inspector noted that this action was being tracked by Adverse Condition Report ACR M3 961288 and Action Request 96035473. The change to TS was approved by the NRC and all three units' TS have been updated to reflect the current organization at Millstone.
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c. Conclusions i
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Based on the above, the inspector considers VIO 50 245,336,423/96-09 04 closed for all l three Millstone Units. TS changes regarding organization changes have improved as a result of corrective actions for the violation.
08.2 Technical Soecification (TS) Noncomoliance (Update SIL ltem 70)
a. Insoection Scoce i Several licensee event reports (LERs) issued during the last year documented TS noncompliance issues. The inspector reviewed five of the LERs for root cause and safety significance determinations and adequacy of corrective actions. The inspector also verified that the licensee met the reporting requirements of 10 CFR 50.73.
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b. Observatioris and Findings (Closedi LER 50-423/96-002: This LER documented that operators discovered, during a planned review of conditional survoillances, that an inadequate surveillance procedure had been used for determining the reactor shutdown margin when unisolating a reactor coolant loop. TS 4.4.1.6.2 requires, in part, that operators determine the reactor is subcritical within 30 minutes prior to opening the cold leg stop valve. Historically, operators had always maintained the reactor subcritical before, during, and after unisolating the loop, however, they had not always met the 30 minute requirement.
Unit 3 staff changed the surveillance procedure, the operating procedure, and the Technical Requirements Manual to clarify the requirements for meeting TS 4.4.1.6.2. The inspector
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reviewed the procedure changes and determined the changes were acceptable.
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(Closed) LER 50-423/96-48: This LER documents that operators failed to adequately test the load shed function of the emergency diesel generators (EDGs) in accordance with TS 4.8.1.1.2.g.6. This TS surveillance must be completed during shutdown, however, the operators performed a portion of the test during plant operations. Upon discovering the error, plant staff appropriately declared the EDGs inopt.rable, satisfactorily completed the surveillance, and then restored the diesels to operable status.
Unit 3 staff attributed the event to lack of verbatim compliance with the TS. Contributing causes were incomplete update of the Master Surveillance Test Control List (MSTCL) and ineffective actions to identify shutdown surveillances. To address these deficiencies, the staff revised the surveillance procedure used for TS 4.8.1.1.2.g 6, reviewed and revised the MSTCL, and reviewed surveillances required while shutdown. They did not identify any additional surveillances needed while shutdown. The inspector concluded the procedure changes were appropriate and that the staff had incorporated the changes.
(Closed) LER 50-423/96-51: -This LER documents that on several occasions operators had
misapplied the 25 percent surveillance interval extension to limiting conditions for operation (LCO) action statements. While this condition had potential safety significance, actual
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consequences were negligible since the equipment met performance requirements when tested at the end of the extended interval.
Plant staff attributed the cause of the misapplication to failure of management to effectively communicate their policy regarding compliance with TS. Subsequently, the unit director reinforced his policy, and shif t managers discontinued applying the grace period to action statements Also, the staff reviewed action statements where operators may have improperly used the TS surveillance interval extension and modified the procedure and forms to provide operators with a clear distinction between action statements and surveillances. The inspector reviewed the guidance modifications, and noted the enhancements which clarified when the grace period was applicable.
(Closed) LER 50-423/97 007: During an engineering review, the licensee identified that reactor engineers had used a nonconservative assumption in determining a shutdown i margin curve. This condition had safety significance because an incorrect curve for determining the reactor coolant boron concentration for adequate shutdown margin could have permitted boron concentrations that may not have maintained the reactor in a shutdown condition. Subsequently, plant staff reviewed actual boron concentration values for the periods in question and compared these values against the required Technical Specification margin. Engineers determined that, due to intentional over-boration, operators had not exceeded the shutdown margin requirements. Therefore, the actual safety consequence of the event was minimal.
The licensee determined the cause of the event to be poor procedures for reactor engineers to use for generating and documenting shutdown margin curves. Accordingly, plant staff revised the applicable reactor engineering procedures. The inspector independently reviewed shutdown margin data and confirmed the operators had not exceeded the TS requirement, and noted the revisions adequately addressed the reactor engineering procedure deficiencies.
(Closed) LER 50-423/97-018: This LER documents a condition where operators determined that they had operated the plant in conditions prohibited by TS because verbatim compliance with certain specified parameters was not possible. For example, a surveillance requirement (SR) for circuit breaker testing required technicians to inject 300% and 150%
of pickup current of the trip elements, without a tolerance band. However, since it is not possible to inject exact currents, operators technically did not satisfy the SR.
Plant staff determined the cause to be operators reading the TS for intent rather than for compliance. Subsequently, the licensee submitted a change to the TS to revise affected SRs and also submitted a change to revise the TS bases. The inspector determined the change requests were appropriate and that the licensee had submitted the requests.
c. Conclusions The LERs described above discuss conditions prohibited by TS. However, because of the low safety significance of the issues and because of the appropriate corrective actions the plant staff initiated, these licensee-identified and corrected violations are being treated as
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Non Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Pollev. The listed LERs are closed. The closure of the LERs, however, does not resolve the generic
. concern for TS compliance. This area continues to warrant continued NRC review.
Therefore, SIL ltem 70 is updated, but remains open.
08.3 (Undate) eel 50-423/96 201 22: Failure to Follow Ooerating Procedure for Reactor Buildino Closed Coolino Water (CCP) System (Update - SIL ltem 37)
a. Insoection Scoce The inspector reviewed the corrective actions taken by the licensee in response to an
. apparent violation of plant technical specifications, b. Ob',ervations and Findings
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, During a special NRC inspection of engineering and licensing activities (IR 50 423/96-201)
the inspectors identified an apparent violation of TS 6.8.1.A which requires that procedures
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be established, implemented and maintained covering the activities recommended in Appendix A of RG 1.33.
The team found that operators failed to implement portions of procedure OP 3208, "Flant Cooldown." The procedure requires the operators to maintain the CCP system temperature from the outlet of the residual heat removal system heat exchangers less than 115*F and to initiate an adverse condition report and notify the system engineer if the temperature
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limit is exceeded. The team identified that these procedure requirements were not l implemented during a shutdown on December 1,1995. The licensee subsequently identified additional events where the CCP temperature limit had been exceeded.
The licensee's corrective actions included:
- procedure revisions to clarify OP 3208; l
- a change to the computer priority alarm log for the CCP temperature alarm point to specify that a condition report is required if the high temperature limit is exceeded; and, e plant operators were briefed on the issue and the seriousness of exceeding an-operating limit was stressed during the briefing.
, The inspector also noted that additional analyses of the system were being performed to increase the temperature operating limit and modifications were being performed to prevent excessive CCP temperatures that could be caused by RHR system control valves failing open on a loss of control air. These actions will provide additional operating margin and system improvements that should help prevent recurrence of the above stated violations.
The system reanalyses and modifications are being tracked by SIL item 13.
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- c. Conclusions The inspector found that the licensee had adequately addressed the specific technical issues associated with eel 96 201 22. However, eel 50-423/96 201 22 remains open pending coinpletion of NRC enforcement considerations.
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08.4 LCJosed) LER 50-423/96-38-00: Hioh Pressure Safety inlection and Charoino Fumo Technical Soecifications (Update - Sll item 70)
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a. Insoection Scooe I
The inspector reviewed the licensee's findings and corrective actions associated with compliance with the Technical Specifications for the high pressure safety injection (HPSI)
and charging (CHS) system pumps during mode changes.
E b. Observations and Findinas
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On October 10,1996 the licensee identified that the TS requirements for the operability of HPSI and CHS system pumps had not historically been met during transitions between i
Modes 3 and 4. Several sections of the TS contain conflicting operability requirements for the pumps and the TS did not contain provisions to permit meeting all of the requirements when transitioning through the 350*F temperature point that defines operation in Mode 3 or 4. A similar prob lem is encountered with the operation of the safety injection to reactor coolant system colo leg stop valve (3SlH'MV8835) which historically was left closed until af ter entering Mode 3.
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This condition was reported to the NRC in LER 50-423/96-38 and the licensee has taken the following corrective actions:
- TS and implementing procedures have been reviewed to ensure the
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requirements can be met for both their intent and verbatim compliance. No additional problems were identified.
- A TS change has been submitted to resolve the specific issues identified in the LER and the affected procedures will be changed prior to entering Mode 4.
- The Unit Director has provided the unit staff with the expectations on l compliance with TS.
c. Conclusions The inspector concluded that the licensee's corrective actions were appropriate. This
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licensee identified technical specification non-compliance is being treated as a Non-Cited Violation, consistent with Section Vll.B. lof the NRC Enforcement Poliev. LER 50-423/96-l 38 is closed.
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V3.11 Maintanntlet U3 M1 Conduct of Maintenance '
M 1.1 General Comments The inspectors determined that the maintenance and surveillance activities observed were properly performed.
U3 M2 Maintenance and Material Condition of Facilities and Equipment M2.1 (Uodate) eel 50-423/96-201-19: Rosemount Transmitters (Update - SIL ltem 18)
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During inspection 96-201 the NRC identified Rosemount transmitters with plastic shipping caps in spare conduit ports and with spare ports open to the environment. The licensee then found that this was not an isolated instance. Apparently, some shipping material had been lef t since ori0 inal construction and other material was left installed when instrumentation was returned from offsite calibration. This discussion will address the specific items noted in the inspection report, the broad corrective actions taken, and the preventive actions taken.
Soecific Corrective Actions The licensee determined that the safety-related Rosemount transmitters, Models 1153 and 1154, needed to have shipping caps removed and open ports sealed with a stainless steel pipe plug. These requirements are defined in the Rosemount vendor manuals and in Procedure IC 3472C41. For Unit 3, the two specific transmitters noted by the NRC having plastic caps and the third one with an open port were corrected by the licensee. The NRC had rioted that three Rosemount transmitters were not contained in the production maintenance management system (PMMS) data base. This has also been noted and discussed in the last periodic resident inspection report (50-443/97-202) as part of the MEPL discussion. The issue of PMMS completeness will be tracked there. The NRC also noted that a transmitter designated as safety related (SR) was being maintained as non-safety related (NSR). This transmitter,3CHS-FT121, has been re-evaluated through the MEPL program (MP3 CD-0865-401) and is now properly classified as NSR. Additionally, two of the discrepant transmitters were classified as SR but the work orders that installed them in 1985 did not reference procedures or vendor manuals. MEPLs MP3-CD-838 and 1032-518 re-evaluated these transmitters and classified them as NSR. Finally, there were noted to be 35 transmitters in Unit 2 that did not have plugs in the spare ports. These problems were corrected on AWO M2-96-02218.
Broad Corrective Actions in ACR M3 96-0708, the licensee committed to research all plant instrumentation in Unit 3, which had spare ports. An inspection was to be performed to determine if the proper plugging material was installed. At part of this effort, a number of instruments were
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identified that had to have shipping materials removed. As an example, of about 400 total ,
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Rosemount transmitters, there were 106 non-safety related transmitters that needed corrective actions. Also identified as having problems were: Fisher transmitters, temperature elements and switches, FCI flow switches, AMOT pressure switches, and
ASCO pressure switches. Of these, there were 12 safety related instruments and four non safety instruments found with problems. The licensee took the necessary corrective actions via the Work Order process.
Some problem areas were noted with the licensee's broad corrective actions. For Unit 3, ACR M3 96-0708 identified a comprehensive corrective action plan (CAP) to address the problem that included seven assignments in AITTS. Assignment No. 90020762 03 was to perform research on all Unit 3 systems to identify any installed instrum1nts that had spare ports, and then Assignment No. 96029762 04 was to perform ti,e inspections to determine
- if the proper plugs were installed and correct them if necessary. These two assignments '
were signed off as completed despite the fact that only a sampling review was done. As an exampts Fisher transmitters and auxiliary steam system temperature switches were not identified and had spare ports that were improperly sealed. Additionally, ACR M3 96-0430 identified ten safety-related auxiliary steam system temperature switches with
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shipping plugs or no plugs in the unused ports. This ACR was closed with other than referring to the CAP for ACR M3 96-0708. However, the CAP for ACR M3-96-0708 did not address these temperature switches. After these issues were identified by the inspector, the licensee provided some justification as to why they believed that the sampling review was acceptable. After further discussion, the licensee issued CR M3-97-2718 to document the fact that corrective action #3 of ACR M3 96 0708 was signed off without completing all of the actions, without completing RP-4.4 Assignment Completion Form, and without initiating an RP-4.2 Assignment Change Form, Unit 3 then re-evaluated
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what had been inspected and what still needed to be inspected in order to ensure that shipping material has been removed and holes plugged where necessary. They then recommenced activities to meet the original CAP. Lists of all instrumentation in Unit 3, sorted by type and manufacturer, were developed. Each type will be reviewed to determine those which have spare ports that need inspection. At the end of the inspection period, the licensee had not completed this part of the review. This item is unresolved
pending completion of the licensee's review and NRC reinspection (423/97 203-06).
Unit 2 performed a oetailed walkdown of transmitters in the plant and corrected identified discrepancies. For this walkdown, a checklist approach was not used. Further, switches
(e.g., flow and pressure switches) were not addressed. Unit 2 has now established a detailed listing of allinstruments that need inspection and has commenced that work.
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Where problems are found, AWOs will be issued to perform and document the work.
During the January to July,1997 period. Unit 3 also performed walkdowns of all environmentally qualified (EO) equipment per engineering procedure EN 31099. This walkdown examined all EQ instrumentation for, among other things, proper closure devices
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and no shipping material remaining. Additionally, the inspector selected a sample of -
instramentation, of various types and manufacturers, and toured the plant to observe the status of the spare ports. Added instruments were observed during the tour. All were
- noted to have shipping materials removed and the proper plugs installed.
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Preventive Actions The Department Manager of l&C for Unit 3 issued an l&C Technical Bulletin (#93) on May 15,1996 to emphasize the issue of removing shipping materials from instrumentation and installing proper plugs where needed. The licensee also noted that the work planning and execution process, as Governed by procedures U3 WC 1 and U3 WPC 2, has been improved and coordination with first line supervisors in maintenance increased. This should help to ensure that proper instructions or procedures are included within or referenced by Work Orders. The inspector reviewed two AWOs (from 10/96 and 1/97) that performed work on safety related Rosemount transmitters and noted that they did reference the appropriate maintenance procedure. Additionally, the licensee performed training on this issue as follows. The March 1997 issue of the "l&C SIGNOT" contained an item discussing the issue, which explained the problem and the corrective actions and which had a test at the end to be completed and retumed to training. ACR M3 96-0708 identified corrective and preventive actions associated with this issue. It indicated that there should also be training for operations. This particular action was not performed and the assignment for training was closed based on the I&C training only. When this issue was identified by the inspector, the licensee issued CR M3 97 2680 to address it.
Lastly, the vendor manual program is being upgraded to address the issue of updating vendor manuals and ensuring requirements from these manuals are appropriately incorporated into procedures. The vendor manual program is discussed elsewhere in this report. eel 50-423/96-201 19 and SIL ltem 18 remain open.
M2.2 lundate) eel 50-423/96-201-18: Auxiliarv Feedwater Pomo (AFW) Lubrication Schedule (Cicsed Partial SIL ltem 18)
During inspection 96 201 the NRC identified problems with the AFW pumps' lubrication schedule, particularly as it related to the periodic surveillance testing. As part of the review, tho inspector reviewed the following documents.
NU Memo, Drechsler to Hess, dated G/21/96, "MS Unit 3 AFW Pumps, Technical Justification to Start the Pump Without Prelube After a 113 Day Shutdown" OIM-041 1, Bingham-Willamette Multistage Horizontal Pumps,3FWA-P1 A/B and P2 OP 3322, Auxiliary Feedwater System, Rev.16, Change 5,8/23/96 SP 3622.1, Auxiliary Feedwater Pump 3FWA*P1 A Operational Readiness Test, Rev.12, Change 2, 8/23/96 SP 3622.2, Auxiliary Feedwater Pump 3FWA*P1B Operational Readiness Test, Rev.13, Change 2, 8/23/96 SP 3622.3, Auxiliary Feedwater Pump 3FWA*P2 Operational Readiness Test, Rev.12, Change 5, 8/23/96
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DC 10, incorporation and Implementation of License Amendments, Rev.1 U3 RP 10, Outgoing Regulatory Correspondence processing and Validation, Rev. O,-
2/14/97 t
Millstone Unit 3 License Amendment implementation Niowup, MP3 LDI 03,3/15/97 Millstone Unit 3 Technical Specifications in order to address the problem, the licensee contacted the vendor, Sulzer Bingham (originally Bingham Willamette), and obtained the needed justification to increase the interval between pump starts without any prelubrication to 113 days (Memo Drechsler to Hess). The vendor has stated that the bearings are lightly loaded and a sufficient quantity of tube oil remains trapped at the bottom of the sleeve type journal bearings in the pumps and drivers, and provides the necessary oil film for startup. All AFW pumps have shaft-driven lube oil pumps that provide continuous lubrication within a second or two after startup. This information was then incorporated into the onsite vendor technical manuals -
for the AFW Pumps, the AFW Pump Vendor Equipment Technical s Surveillance Test Procedures, and the Operating Procedures. The concern, noted in the inspection report, about not having a meaningful as found surveillance test, is addressed since the licensee tests the pumps without prelubrication, throughout the entire quarterly test interval,
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The licensee also implemented preventive actions as follows. The Vendor Equipment Technical Information Program is being improved with the issuance of a new procedure DC-16. The review of this area is discussed in Section V.E.1.lof this report. Procedures DC-
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10 and U3 RP 10 discuss the processing and implementation of license amendments, and
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provide controls to ensure that appropriate actions are taken. The licensee also developed
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MP3 LDI 03 to provide for added monitoring of the implementation process by licensing personnel.
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- This eel package is technically closed. However, the eel remains open pending completion L
of enforcement actions by the NRC, therefore eel 50-423/96-201 18 and SIL ltem 18 are updated.
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. U3 M8 Miscellaneous Maintenance issues M8,1 . (Closedl URI 50-423/96-06-14: Potential Cloaging and Erosion of ECCS Throttle Valves, and FCCS Pomo Run-out ootential (Closed SIL ltem 45)
(Closed) LER 96-029: Functional Deticiency in Settina ECCS Throttle Valve Eositions
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Imolementation of ECCS Flow Modifications a. InSaftetion Seng.g As documemed in NRC IR 50-423/96-00, issues were addressed concerning identified
, problems with the emergency core cooling system (ECCS). The system contains eight cold leg injection valves and four hot leg injection valves requiring throttling adjustments to introduce resistance in each branch line. The resistance must be high enough to limit total
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flow to prevent run-out of the charging pumps (CHS) and safety injection pumps (SlH)
, during the recirculating phase of a loss of cooling accident (LOCA), yet supply the required
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amount of flow to satisfy post LOCA core cooling requirements. The valves must also be open f ar enough to pass the debris that passes through the sump screen, and prevent
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erosinn of the valves due to cavitation. it was also identified that, during the post LOCA phase, additional pump run out problems existed because of the " pump boost" effect
. Imposed by the elevated suction pressure from :he discharge of the containment recirculation spray system (RSS) pumps. The inspector reviewed the licensee's design change and TS change to evaluate resolutions for the above problems, b. Observations and Findinas The licensee indicated in the Licensee Event Report 423/96-029 una an engineering evaluation determined that a functional deficiency in the setting of the emergency core
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cooling system throttle valve positions was a condition that alone could result in the loss of the charging and high head safety injection safety functions in the recirculation phase, t This is an apparent violation of 10 CFR 50, Appendix B, Criterion lil (eel 423/97 203-07).
Design Change M3-96077 was implemented to correct the concerns discussed above. The r.hange added two types of orifices in the injection lines to allow the throttled valves to be 1 opened far enough to address the debris and erosion problem and still prevent run-out of the CHS and SlH, including the " pump boost" effect, during the post LOCA event.
The inspector reviewed calculation SAE FSE C-NEU 0003 for the design of orifices,1). a
barrel type; and 2). a modified flow orifice to replace the existing one in each flow line, The calculation was bounded by selecting a fixed valve opening (two and one half to three turns,0.125 inches) which is sufficient to pass debris that could be introduced into the system and also prevent cavitation. Another assumption bounded the opening of the orifices to easily pass any debris that could enter the system. The inspector noted that the
. calculation conclusion showed that the barrel orifices were to be 12 inches long and would
have an opening of 0.125 inches. By reviewing the valve manufacturer's technical manual
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i the inspector verified the throttled valve openings listed above were sufficient to pase .I debris greater than 0.094 inches (the oponing of the cump screens). j The design calculation showed that all of the branch lines did not require an orifice. Ten of the twelve injection lines required addit;onal flow resistance Of the ten, eight required
- both the barrel and flow element plate change (all cold leg injection). Two' hot leg injection
- lines had enough flow resistance to negate the need for any type of orifice, while the other two only needed a flow element orifice plate change. The flow element flow orifices were.
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changed to make the orifice holes smaller, but large enough to pass the allowed debris.
These flow elements will be permanently installed and enable a temporary flow device to be attached for flow balancing purposes. New instruments were also purchased to accommodate the new flow elements. These instruments are not in service during operation. The licensee purchased twelve additional blank flow elements to enable finer balancing of the injection lines during testing if it becomes necessary and ensure the valves
- remain at two and one half to three turns open as designed, i The inspector reviewed purchase order MB-22193 D, used to purchase the orifices, and the certificate of conformance for the orifices which showed that they were in accordance with the purchase order. The inspector walked down the system and observed the orifices installed. The inspector selected an installed orifice and traced the inscribed numbers to the design paperwork. The inspector verified that the installed orifice was intended for that location. The inspector also verified that the welds were performed in accordance with the
, approved welding program at Millstone by a qualified welder.
The licensee used a code case during the implementation of the design change, Code Case N-4161, " Alternate Pressure Test Requirements for Welded repairs or installation of Replacement items by Welding, Class 1,2, and 3,Section XI, Division 1" was used, with i NRC's permission (letter dated January'25,1995) to perform acceptance testing. The
- Code Case required additional dye penetrant testing for acceptance of the welds, provided
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a full visual examination of all welds is performed at normal system pressure and temperature to check for leaks. The inspector verified documentation for the dye penetrant tests that showed no indications existed. The system had not been tested as of this
!- inspection since other supporting systems were not available to accommodate the testing.
During a walkdown of the containment sump area the licensee discovered larger than the allowable 0.094 inch openings around 1 beams and plate to angle iron contact points in the
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sump enclosure. The inspector noted that a design change was issued to repair the openings, but had not yet been implemented.
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A TS change was requested on April 28,1997 (subsequently revise on October 15,
~ 1997), to include an increase in the required differential pressure at recirculation flow for i
CHS and SlH, a decrease in the required individual CHS and SlH line flow rates, an increase in the allowed individual SlH pump runout flow rate, and editorial changes to required surveillances. This change has not been issued by the NRC, and will be required prior to testing.
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Chtnges have not been made to the FSAR; ho' wever, the design basis documents (DBD) at Millstone 3 were in the process of change, The former DBD contained the entire design basis including calculations; correspondence between the licensee, AE's and vendors; prior design changes; etc. The new document c'.slied the *Desigr Basis Summary" will contain the reference guide to all design documents for that system, The inspector verified that the changes made to the ECCS were documented in the " Design Basis Summary for
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ECCS," 3DBS NSS-005, i c. Conclusions The inspector concluded that the design deficiency that caused the system to operate in a degraded condition since the licensing of the plant was an apparent violation, The installation of the flow orifices should allow the throttled valvas to be opened wider to prevent plugghg of the valves and erosion due to cavitation. The inspector also concluded
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that the design change was performed according to approved plant ptocedures that
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conform to NRC regulations, However, the following items remain open: The system has not been tested to prove the orifice changes will remedy the open items listed above, Because the design change was not complete, the training of operators was not conducted, Daring the system testmg, visual ebsuvation of the welds f ar leaks are required to be documented. Also, the design change to repair the larger than allowable open;ngs in the sump area was not implernented, Unresolved item 50-423/96 06 14 and Sit item 45 are closed, as is LER 96-029, which documents the deficiency with the identified ECCS throttle valve settings and the need for the design change to instal! the restricting orifices However, inspector follow item, IFl 50-423/97 203 08, will be opened to track the remaining open items discussed above and to review the closure package for LER 50-423/96-039 when it is submitted.
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M3.lli Enoineering U3 E1 Conduct of Engineering E 1,1 RSS Desian Deficiencies (Update SIL ltems 1 & 85)
(Closed) LER 50-423/96-07. Sucolements 1 & 2: Containment Recirculation and Quench Sorav Svstem Outside Design Basis a, Insoection Scoce 192903)
In letter NES-40098 to NU dated 11/13/SS, Stone & Webster (SWEC) identified a temperature transient in the Millstone Unit 3 containment recirculation spray (RSS) system due to loss of service water (SWP) flow to the RSS heat exchangers, SWEC noted that loss of SWP cooling could result from an assumed single active failure of a SWP pump or an RSS heat exchanger SWP iniet valve, if either single active f ailure were postulated coincident with a large LOCA, containment sump temperature would rise to a temperature higher than the temperature that SWEC initially used to qualify the RSS system. The licensee subsequently determined that the postulated transient raises the accident
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environmental temperature and pressure inside containment in addition to raising the temperature of the SWP water in the containment sump. This issue was discussed and documented further as an apparent violation (eel 423/96-06-13) in IR 50-423/96-06.
Likewise, other fiSS design deficiencies, identified by the licensee as part of ongoing configuration management program (CMP) activities, are documented as an additional apparent violation eel 423/97 202-09.
During this inspection period, the inspector reviewed documents of record for a portion of Train B of the RSS system to confirm that the licensee had revised the original design documents or prepared new documents to address the above postulated transient with the elevated containment temperature effects. The inspector also reviewed the licensee's plans for corrective actions to address the additional RSS design problems related to net positive suction head water hammer and vortexing concerns.
b. Observations and Findinas The design basis for the RSS system is documented in Design Basis Summary (DBS)
Document No. 3DBS NSS-003 (Revision 0), dated May 27,1997. Section 14.0 of inis DBS additionally tabulates the open items for the RSS system review that the licensee has currently documented, including CR M3 97-0039, "Possible Two Phase Conditions in RSS Piping," and CR M3 97-0128, " Potential for RSS Piping Failure." The licensee prepared these CRs during a review of the RSS system for Generic Letter (GL) 96-06 concerns.
The Calculation No. SDP RSS 01361M3 stress data package documents the mecnanical and structural design basis for RSS piping, equipment and supports. This calculation set updates Revision 3 of the stress data package that SWEC issued on 11/9/85 The licensee revised the stress data package to add three new conditions / operating modes to address the postulated single active f ailure of the loss of one train of SWP to the RSS heat exchangers, including Condition No. 7 A/B, which postulates one train of the RSS system discharging uncooled surrp water to the spray headers.
Additional calculation set piping analyses qualify the Train B portion of the RSS piping system. A Pipe Stress Analysis Criteria Document (NETM 44, Revision 2), dated August 5, i 1985 documents the lower-tier design requirements for piping analysis, Table 4-6 of NETM 44 lists the governing load combinations for the Normal / Upset, Emergency and Faulted design conditions for ASME 111, Class 2 and 3 piping except for QSS, RSS and Safety injection (SI) piping. Table 4-5 lists the governing load combinations for OSS, RSS and Si piping, and requires that the NC 3600, Equation 11 load combination be satisfied for the Faulted condition in addition to Equation 9. These design requirements are consistent with the load combinations listed for the QSS, RSS and SI systems .n FSAR Table 3.9B 11.
The licensee's implementation of the Equation 11 Faulted load combination in the calculations of record for Train B of the RSS system was taken as the focus of this programmatic review.
Equation 11 requires that the following loads be combined: Pd, D, T R', A' and X. The term R in Table 4-5 of Reference 9 is defined more explicitly for the Faulted condition as R'
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in FSAR Table 3.9B-12. The term Pd represants tbo piping internal pressure load due to the piping design pressure. Reference 3 defines the design and operating pressures for the RSS system. The term D represents tne static load, including the deadweight of piping, flui.f, insulation and equipment. The term T represents the load due to the temperature of the piping fluid. Calculation No. 2,uP.rlS401361M3 defines the design and operating temperatuies of the RSS system. fiie term R repiesents the piping load due to the Faulted thermal growth of the equipment and/or structures to which the piping is attached.
Calculation No.12179 NS(B) 168 (Revision 1), dated August 5,1985 calculates the radia!
and vertical displacements of the ;ontainment structure for Faulted temperature. The referenced piping analyses additic qally calculate the Faulted thermal growth of the RSS pump and cooler nozzles. The ter n A' represents the piping load due to the Safe Shutdown Earthquake (SSE) displacement of equipment and/or structures to which the piping is attached. ApPndix B of Calculation No.12179-NP(F) 79A-012, dated August 12, 1996 tabulates the SSE displacements of the major Unit 3 building structures, including the containment st ucture and the engineered safety features (ESF) building. The term X defines the load due to the Faulted pressure dispiacement of the containment. Reference 10 additionally calculates 'he radial and vertical displacements of the containment structure due to Faulted pressure.
A programmatic review of the current calculation sets confirmed that each piping analysis documented the above design parameters.
The inspector also reviewed pipe support calculations to confirm the design adequacy of the minor modifications perform'ed on these RSS supports. Table 3.5-1 of the governing
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support design criteria document (NETM 45, Revision 1), dated September 19,1985, details the governing load combinations for linear type pipe supports installed in all piping systems except the OSS, RSS and Si piping systems. Table 3.5-2 details the more restrictive Faulted load combinations for the QSS, RSS and SI systems. However, these pipe support load combinations are not documented in the FSAR. The licensee issued CR M3 97 2722 to amend the FSAR to incorporate the pipe support load combinations documented in Tables Q210.36-1 and Q210.36-2 of FSAR O210.36. This CR also documents a discrepancy between the pipe support load combinations documented in Table 3.5-2 of NETM 45, Revision 1 for the Containment Spray systems and the load combinations dommented in Table 0210.36 2 of FSAR O210.36. The licensee has indicated that t:.e go /erning load combinations for piping and pipe supports for the reanalysis of t' e Containment Spray systems are extracted directly from Table O210.36-2 of FSAR Q210.36 and documented in Millstone Reevaluation Project Memo (MRPM) 14,
"MRP Supplemental Criteria Document.'
The referenced pipe support calculations were reviewed to confirm that the support loads were transmitted from the piping analyses of record and that the support loads were combined in accordance with the Faulted load combinatiors documented in MRPM 14.
dditional Design Change Notices (DCNs) in support of pipe support modifications were also reviewed to confirm that the minor design modifications documented in the DCNs were consistent with the design changes documented in the pipe support calculations, No discrt,>ancies were identified in the calculations during this review.
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. 64 Additionally, the inspector reviewed the licensee's current activities to re-qualify affected RSS equipment for the higher Faulted temperatures, including re-rating of affected equipment due to higher flow temperature and equipment qualification (EQ) reviews due to potentially higher room heatup.
Plant design change record, PDCR M3 96054, dated August 8,1997 authorizes the re-rating of affected piping and equipment for the increased 260 * F design temperature. The applicable DCNs that implement the increased RSS design temperature were reviewed to confirm that NU obtained vendor review and approval to re-rate the affected equipment.
No discrepancies were identified during this review.
Another DCN (DM3-01-1530 96), dated May 30,1997, re-rated the RSS piping expansion joints. This DCN was separately reviewed because there are several open condition reports posted against the expansion joints, including ACR M3 97-0407, documenting a potential design flaw that may reduce the maximum permissible magnitudes of the relative axial and lateral displacements of the expansion joints, and CR M3 97 0836, documenting potential inaccurate modeling of the expansion joints in the piping analysis. A Flexonics bellows
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design calculation (D30329) was reviewed and no discrepancies were identified. However, the inspector did discuss with the licensee their consideration of the reorientation of certain expansion joints to reduce the Icads on the tie rods.
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With respect to EO review of potentially affected RSS equipment, an Engineering Work
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Request (EWR) was issued on August 15,1997 to authorize the preparation of a
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calculation to determine the wo'rst case steady state temperature in the RSS cubicles and the impact on adjacent cubicles. The room temperatures defined in the calculation would serve as a basis for the revision of the EQ profiles for these rooms, and an evaluation of
, the potentially affected equipment installed in these rooms.
Finally, the inspector reviewed draft safety evaluations for the modifications associated with elevated containment temperature design concerns and certain ACRs relevant to the functionality questions involving the RSS pump suction design. The safety evaluation addressing the latter issue, as well as all RSS functionality concerns with net positive suction head, water hammer, and vortexing was not yet available for review. Additional
- NRC review of the final safety evaluations associated with both the elevated temperature and system functionality issues appear necessary to evaluate licensee efforts, both for completed modifications and further planned design changes.
c. Conclusions Eels 50-423/96-06-13 and 97-202-09 respectively document apparent violations in the RSS system and related design configurations. Dunng this inspection, a review of the ongoing licensee re-analysis and design change efforts to address the identified deficient
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conditions was conducted. This review effectively closes Supplements 1 and 2 to LER 50-423/96-07, which itself was closed in IR 50-423/96-06. While some questions were raised and a CR was generated to augment relevant, affected FSAR data, this inspection identified no substantial design change or performance concerns. The licensee has been requested to provide the final Safety Evaluations related to both Sllitem 1 (temperature
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L issues) and SIL ltem 85 (other RSS system functionality concerns). Pending receipt of these safety evaluations, further review by the NRC, and the completion of corrective actions by the licenses to address both of the above apparent violations, SIL ltems 1 & 95 remain open and are hereby updated in this report.
U3 E2 Engineering Support of Facilities and Equipment
E2.1 (00date) eel 50-423/96-201-37: Installation of filters on batterv room i ventilation system fire dampers (Closed - Partial SIL ltem 79)
This_ item identified temporary filters that had been installed since original construction without any design authorization or controls. These filters were installed on the inlet lines
! for the battery room ventilation system, next to the fire dampers, for Battery Rooms 1 through 5. The licensee noted that inspections of the filters had been performed per '
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Maintenance Form 3712NA 1 since 1987.
Af ter the NRC inspection, the licensee removed the temporary filters and initiated DCR No.
, M3-96073 and DCN No. DM3 S-0175 96 to install permanent filters. CR-M3 96-0923 was also issued to define corrective actions to prevent recurrence. The design, installation, and
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initialinspection of the new filters has been completed. The inspector observed the
installations in the company of the cognizant engineers. The FSAR was revised to incorporate the necessary mention of the new filters. Drawings were updated as
- eppropriate. A MEPL evaluation of the new filters was performed that classified them as non safety related components.' The inspector noted that some labels on the filter dampers
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! were loose, incorrect and that no labels had been installed on the new filter assemblies.
The licensee corrected some of these deficiencies and folded the remainder of them into
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the ongoing label upgrade program in process per Procedure OA-9, System and Component 4- Labeling.
i The inspector discussed the use of temporary filters with the ventilation system engineer who stated that he had reviewed all other safety related ventilation systems, and that no
, other temporary filters were in use. The inspector performed a sampling inspection in the plant, and did not identify any temporary filters in use. The licensee has controls for '
temporary modifications in place (in Procedure WC-10) to preclude recurrence of the event.
1 The licensee has established inspections for the filters as follows: Procedure SP3712NA l and related Maintenance Form 3712NA-1 for Battery Rooms 1 through 4: and Procedure MP 3780AA with related Maintenance Form 3780AA 1 for Battery Room 5. The design
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calculations note that Battery Room 5 requires clean filters (i.e., very close attention to
- filter cleanliness). The inspector noted that neither the procedures nor the Maintenance
Forms had specific criteria for the filter inspections and that there was no reference about
, the special attention that the filter for Battery Room 5 needed. There was also no line item 4 on the Maintenance Forms for the filter inspection. The inspector reviewed completed
{ Maintenance Forms for the past three months and found no reference to or comment about l' the filters. The maintenance supervisor stated that personnel replace the filters when they become dirty and change color but that they have no different criteria for Battery Room 5.
The inspector toured the plant over the course of the inspection period and noted that the d
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filters were being maintained acceptably clean. The licensee revised both procedures and forms to add documentation that filters are satisfactori!y clean.
This specific techricalissue is closed. SIL ltem 79 is hereby updated. The enforcement aspects related tt this item remain open pending further NRC action on the Millstone Eels.
E2.2 (Uodate) eel 50-423/96 201 13: Discrecancy in the Useable Volume of the Condensate Storage Tank (CST) (Closed Partial SIL ltem 37)
The CST is used as a source of water to supplement the Demineralized Water Storage Tank (DWST) in acc; dent analyses and in the TS, Previously the TS required 334,000 (334K)
gallons of water in the DWST or if the DWST were not fully available then the TS required 334K gallons combined between the CST and DWST. However, the licensee identified that 30K gallons of CST water are unavailable due to f actors such as location of the suction line and vortexing in the tank. Thus, the licensee concluded that to meet the requirements of the accident analysis at least 364K gallons of water combined between the CST and DWST would be needed. However, the licensee failed to take actions to promptly address this finding (e.g., submit a revised TS request, train operators, revise the Technical Requirements Manual (TRM), and revise procedures).
Subsequent to the NRC finding, the licensee performed interim actions in 1996, including changing the TRM and revising procedure SP 3670.1, " Daily & Shiitly Control Room Rounds," to require at least 364K gal lons of water combined between the CST and DWST.
In preparation for the TS change submittal, the licensee completed calculafon 97-ENG-01397 D3 on May 9,1997. This document calculated instrument loop err:r for the CST levelinstrument. On June 19,1997, the licensee submitted their proposed TS change request (PTSCR #3-15-96) for the DWST/ CST. This request included instrument error as well as suctinn pipe location and vortexing into the unavailable water determination. As a result, the JT unavailable water was now 50K gallons and the proposed TS required 384K gallons combined between the CST and DWST. This PTSCR was coded as being needed to be completed prior to unit startup. This TS is only applicable during Modes 1,2, and 3. Since Unit 3 is currently in Mode 5 - Cold Shutdown, no further interim actions were needed. During the inspection, the PTSCR was approved by the NRC. The licensee is now in the process of implementing procedure and TS manual changes in accordance with proce. ure DC-10, incorocration and implementation of License Amendments.
Regarding the more general question of an appropriate corrective action program, the licensee has established a Corrective Action Manager with a supporting staff, has revised and improved the corrective actions procedure, RP-4, and has given significant resources and attention to improving the overall site corrective actions program.
This specific violation is technically closed. SIL ltem 37 is hereby updated. The eel remains open pending further NRC enforcement actions.
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E 2.3 (Closed) LER 50-423/96-049 00: Class 1E to non Cirss 1E Electrical Cable Seoaration Noncomoliance (Closed) LER 50-423/96-015-03: Inadeouate Electrical Seoaration Between Redundant Protection Trains Associated with Reactor Trio Switches and Reactor Trio Breaker Indicatino Llohts (Update SIL ltem 57)
a. Insoection Scooe (92903)
LER 96-049 00 and its supplement, LER 96-049 01, documented the concern regarding deviations of minimum separation distances between Class 1E and non-Class 1E cables in the cable spreading and instrument rack rooms. ACR M3-96-1337 identified the specific noncompliant items and their applicable corrective actions.
LER 96-015-03 (an update of LERs96-015 00,01, and 02) identified additional Main Control Room (MCR) panels in which noncompliances with electrical separation requirements were found. ACRs M3 96-0080, M3 96-0536, M3 96-0552, M3 96-0579, M3 96 0607, M3 97 0263, and M3 97-0276 provide information on the specific noncompliant items, and tho applicable corrective actions.
The inspector reviewed the licensee's ongoing corrective actions to address ts.c above concerns, b. Observations and Findinas LER 96-049-01 identified 976 deviations of minimum separation distances between a Class 1E and a non-Class 1E cable in the cable spreading and instrument rack rooms. The licensee indicated that about 160 noncompliant items have been corrected through "re-training" (i.e., redundant cable trains tie-wrapped to minimum separation distances) of the cables, and repair of Sil-temp protective wraps. Another 540 noncompliant items are related to inadequate separation distances between cable trays.
ACR M3-96-1337 identified specific electrical separation violations u the cable spreading room. DCN DM3 00-1569-96 and AWO M3 96-19906 were initiated to implement the installation of cable wraps on the affected non Class 1E cables (exiting the conduits 3CC446ND,3CC446NC,3FK416N11 and 3FC416N12), and Class 1E cables exiting the conduit 3CC4010A. The licen.iee's QC inspection results for AWO M3-96-19906 indicated that the completed installation of cable wraps on the affected cables met the acceptance criteria for electrical separation. Based on a field walkdown in the cable spreading room, the inspector did not find any operability concerns, in addition, the inspector noted that the cable-wrap installations on cables exiting conduits 3CC534NX and 3CX405BB were satisf actory. These cable-wrap installations were implemented to correct electrical separation noncompliances identified in CR M3-96-0148.
The inspector also conducted field walkdowns in other plant areas, e.g., diesel generator room " A", ESF room "B", chiller room, charging pump room, and hydrogen recombiner building, to assess whether the implementation of cable-wrap installations and cable tie-
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wrap arrangements were in compliance with separation requirements. The cable wrap and
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cable tie wrap installations were implemented to address the corrective actions for CRs
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M3 971352, M3 97-1414; M3 971445, M3 97-1575, and M3 971634. The inspector confirmed the cable-wrap and cable tie-wrap installations on the aff seted cables met the electrical separation requirements. Since the work on correcting electrical separation noncompliances is ongoing and expected to be completed prior to plant startup, this issue
, will remain open.
l LER 96-015 03 identified additional MCR panels where electrical separation noncomplianm were found. Work is in progress to correct the identified noncompliances.
The inspector observed the actualinstallation of tie wraps on the "B" train wiring in ventilation panel 3HVS*PNLVP1 per AWO M3-9714750. Prior to actual installation work,
[ a pre-job briefing was provided to the on shif t MCR personnel, in accordance with procedures, the associated circuits at power panels were de energized to isolate the VP1 panel for work to be safely accomplished. The inspector did not have any concems with the tic-wrap installations in the VP1 panel.
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The l' asee's training program and revision of applicable work planning procedures to enhance electrical separation inspections had been addressed in NRC IR 97-205; The-
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inspector had no new concerns in these areas.
One corrective action for the issue concerning the electrical separation vio;ations was to enhance Engineering Specification SP-EE-076 to include specific electrical separation
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inspection attributes. DCN DM3-00-146196 was initiated to implement this change to 4 administrative procedures. The inspector noted that revisions to Section 21 of i Specification SP-EE-076 included a provision for less stringent criteria for minimum
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separation distance between Class 1E and non-Class 1E circuits where plant arrangements preclude the minimum separation distances. The licensee indicated that the technical justification for exception to such separation criteria was based on Wyle Test Report
47506-02 which documented test results on cable configurations with no separation distances. The test data for the worst-case cable configurations showed no insulation
- damage under the simulated fau;t conditions for assumed ambient conditions. The inspector considered the use of the Wyle Test Report data reasonable to support the technical basis for some ext.eptions to separation requirements.
c. Conclusions The licensee is continuing work on correcting electrical separation noncompliances in the MCR panel boards and other plant areas to meet the plant startup deadline. For example, installation of separation barriers in other MCR panel boards have not been completed.
Since corrective activities are ongoing, the electrical separation issue will remain open: SIL-Item 57 is updateo. The specific referenced LERs and supplements are hereby closed.
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E2.4 (Undate) eel 50-423/96 201-02: Service Water Booster Purno Bvoass Jumoer Safetv Evaluation Deficiencies (Update - SIL ltem 78)
a. Insoection Scoce (92903)
This inspection included a review of Escalated Enforcement item (EEI) 50-423/96-201-02 and related documents. ACR M3-96-0924 addressed an apparent violation of 10 CFR
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50.59 that was discussed in NRC SpecialInspection Report 96-201. This report identified -
the inadequacy of safety evaluations for the Service Water System (SWP) Booster Pump Bypass Jumper (BJ) 3 90 20, and subsequent deletion of the compensatory manual action as an issue for escalated enforcement action. ACR M3-96-0357 documented the issuance of LER 50-423/96 005 00 that described the installation of BJ 3 90 20 which inadvertently defeated th.. high temperature auto start feature of the Service Water Booster Pumps for the Motor (,oritrol Center (MCC) and Rod Control Area (RCA) air conditioners (ACUS). The inspector reviewed the licensee's corrective actions to address the SW booster pump BJ Concerns.
b. Observations and Findinas
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i ER 96-005-00 and its supplement LER 96-005-01 documented the discovery that an automatic start feature of a SWP Booster Pump was disabled. The original control logic
caused the outlet isolation motor-operated valves (MOVs) on both trains of Service Water cooling to the MCC and RCA ACUS to ooen on high temperature in the ACU duct, or on a Loss of Power (LOP) signal. Both isolation MOVs are in the same fire zone and therefore, the valves could fait closed during a fire or seismic event. As a result, a decision was made to leave the valves normally open. An open isolation valve would give a start signal to the SWP booster pump. When the valves were changed to the normally open position, the booster pumps operated continuously.
In May 1990, BJ 3 90-20 was installed to prohibit the SWP booster pump from operating unless required. This jumper defeated the pump start on an open isolation valve, and allows a direct pump start on an LOP signal. However, this jumper also defeated the pump start on high temperature in the ACU duct (Reference ACR 10795). The deletion of the
, high temperature start signal was not addressed in the BJ technical evaluation or safety evaluations, in addition, operator actions to start the booster pumps af ter reset of an LOP
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signal were not proceduralized (Reference ACR 10782). These operator actions were I specified to satisfy the requirement that two independent actions are needed to stop -
equipment which was started from a LOP signal.
PDCR MP3 94-099, Revision 1, was initiated to remove BJ 3 90-20 from the control circuit for interlock between the MOVs 3SWP'MOV130A/B and booster pumps 3SWP*P3A/B.
The controllogic designed to open the MOVs was modified to start the pumps instead.
i .This permanent modification would also provide the additional reset function following a LOP signal. - Details of the specific modifications are provided in DCNs DM3 S 361-94,
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DM3-S-830-94, DM3-S-885 94, DM3 S-082 95, and DM3-S-365 95. The modifications were completed in accordance with AWOs M3 94-22462, M3 94-22472, and M3-96-
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04600 Based on a field walkdown, the inspector verified that electrical conduits to the l-l l
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MOVs 3SWP*MOV130A and 3SWP*MOV130B were removed, and a new latch relay (General Electric CR120BL) was added to each control circuit for 3SWP'P3A/B. The inspector did not have any operability concerns with the installed modifications.
The inspector reviewed the Inservice Test Proceduro IST 3-95 003, Revision 0, " Service Water Booster Pumps 3SWP*P3A and 3SWP*P3B Operational Test," which provides
- guidance for post-modification testing of PDCR MP3-94-009. It was noted that IST 3-95-003 contained well written instructions for testing the pump starts on signals for LOP and ,
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high temperature in ACU ducts. The inspector also reviewed the operability test data foi the most recent surveillances per procedures SP 3626.10 and SP 3626.11 on August 16, 1997 and September 11,1997, respectively, for the SWP booster pumps 3SWP'P3A and 3SWP*P3B. It was found that the differential pressures and discharge flowrates of the pumps were within the acceptable range of operability limits. No concerns were identified.
Revisions were made to Operating Procedures OP 3326 and OP 3353 to verify operability
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of the SWP booster pumps after an LOP event. The inspector reviewed OP 3326, Revision 18, and OP3353.VP1 A, Revision 0 (Change 10), and noted that the procedural changes
] were appropriately incorporated. Revisions to Nuclear Group Procedure NGP 3.12 were also implemented to address concerns related to inadequate guidance for screening of 10 CFR 50.59 safety evaluations. The inspector noted that the major revisions incorporated in Procedure NGP 3.12, Revision 10, included the definition of equipment important to safety, the requirement for a safety evaluation ic'entification number, use of an improved safety
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evaluation form to enhance the quality of safety evaluations, and formal guidance for safety evalua* ion screening. The contents of these revisions were consistent with industry guidelines. Laining materials on 10 CFR 50.59 Safety Evaluations were developed for training of licensee staff responsible for safety evaluations. The inspector verified the training course untents were consistent with the Procedure NGP 3.12, Revision 10.
The inspector reviewed the revisions made to Millstone Station Procedure WC-10, Revision
! O, " Jumper, Lif ted Lead, and Bypass Control," which superseded Nuclear Group Procedure
! NGP d.05, Revision 4. It was found tht Procedure WC 10, Revision 0, included requirements for PORC and management review of procedural changes associated with the installation and removal of bypass jumpers. These requirements are specified as instructions in the jumper device control sheet flowchart contained in Attachment 1 of WC-10, Revision O. The inspector considered these procedural revisions to be adequate for management oversight of the bypass jumper program, c. Conclusions
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The licensee's corrective actions to address the above issues concerning the M P booster pump BJ were determined to be acceptable. The technicalissue for the eel is considered closed; however, enforcement considerations are still under review by the NRC. The broader issue regarding inadequate safety evaluations to satisfy 10 CFR 50.59 requirements is a NRC restart issue. SIL ltem 78 and eel 50-423/96 201-02 are hereby updated.
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U3 E3 Engineering Procedures and Documentation ,
E3.1 Material. Eautoment and Parts LisMMEPL) St3tus _Undate Chemical !
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Consumabing (Update SIL ltem 25) !
I The majority of the open MEPL stems front the last resident report are unchanged and still j
- open During this report period, the inspector reviewed some of the practices associated t with categorizing chemical consumables used in the plant. The following documents were
utilized in the review.
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Unit 2 MEPL No. CD 1276 for penetrant Kroll 7 Unit 2 MEPL No. CD 1308 for anti seize compound ;
- Unit 3 Hard Copy MEPL !
1 CC 1, Control of Chemical Consumable Products, Rev. 1, 3/31/97 4
) Chemical Consumable Products List (CCPL) I
? Draft procedure NGP 6.16/MC 6, Quality Assurance for Nonsafety items
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-- ACR 06516 The admin!strative controls for chemicals has evolved over the years at Millstone. ,
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Curruntly CC 1 provides controls for ordeling, receiving, transporting, and using chemical consumable products, particularly as they relate to its classification as A,8, or C for use on ,
the primary system surf aces. The procedure subject matter expert stated that the
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appropriate end use of chemical products is determined by the end user in conjunction with j engineering, Ch9mical products which raay be used on the pressure retaining metal t
' surfaces of the primary and secondary systems are classified as Category A and receive test!ng pet CC-1 to ensure compatibility with their use. The CCPL is maintained to document which chemicals have been approved in Categories A, B, and C. The safety
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classification of components end consumables is determined via the Material, Equipment,
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Parts Lmt (MF ) Evaluation process. Not all Category A consumables are classified as safety-relater VJt they may hava additional requiremants specified by engineering as part
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of the MtiPL process. For example, MEPL CD 1275 categorizes Kroil penetrant as non-
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t i safety related o' ut calls for a random sampling of Kroil to be tested for chlorides. This has -
apparently not been performed over the years, as r.oted in ACR 06515. The licensee has
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instituted a new procedure NGP 6.16 to better address any necessary controls on non-
, safety related equipment. This prccedure was stillin the review and approval cycle at the end of the inspection, and was recenti/ changed to f,iC 6 with the same title. The inspector noted that Kroilis maintabed in the wa'ehouse for use, and had not been ee-
. tested per the MEPL specifications. The CCPL c(ordinator examined tne Kroil in the -
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warehos.se, noted thare wera no certifications w,th it, and selected a samp'e of the Kroil !
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and sent it out for tosting. He also contacted the vendor and received the latest specificatior's sheet on the material, which showed that its specifications are still ,
acceptable.
MEFL CD 1308 evaluated anti-seize compound and recommended that the material for Category A uso be only purchased as OA Category 1. The inspector noted that the current CCPL has both CA Category 1 and non OA anti seize compounds listed as Category A
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chemical consumtbles. The designations of OA and non OA were obtained from the MIMS -l
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computer system, and are used for purchasing, There did not appear to be any MEPL that justified purchase of these items as non OA. The Unit 2 MEPL engineer is investigating this.
When consumable items are to be withdrawn from the warehouso, the parts technicians rnust check that a valid MEPL exists, and that the materials request matches the MEPL.
However, there is currently no effective method for tracking MEPL status on consumable items or ensuring that any requirements established in the MEPLs are met during the purchase and use of the item. The hard copy MEPL, which is used for items that do not have a specific component identification (such as consurr. ables), has not been kept up to-date. The licensee stated that the MEPL program would be updated to appropriately address the consumable items. They also stated that the information from the MEPL ovaluations, the CCPL, and from Procurement would be properly integratod, and that the MIMS system would be updated to track any MEPL requirements for const mables to ensure that they are addressed when purchasing the consumables. The new MC 0 would be the mechanism for actually performing the necessary tests or examinations.
MEPL SIL ltern 25 remains open and is updated to consider the additional chemical consumable issues, discussed in this section.
U3 E8 Miscellaneous Engineering issues E 8.1 [ClandLLER 50 423/97 025 00: Failure to Feier TecbDicalsoccification 3.0.3 Upon Loss of Vjial AC Bus VIAC 1 a, lamectior Scoce (92700)
LER 50 423/97-025-00 identified a failure to enter TS 3.0.3 upon the loss of 120Vac Vital Bus VIAC-1 for two minutes on March 27,1988. The cause of this event was a failure to address an inconsistency between TS 3.3.2 and 13 3.8.3.1. The loss of Vital Bus VIAC 1 resulted in the inoperability of four channels of the 4.16 kV emergency bus undervoltage -
grid degraded voltage detection instrumentation for the respective 4kV emergency buses, 34C or 340. The inspector reviewed the licensee's corrective actions to address this concern.
b. Observations and Findings ACR M3 97-0235 documented the discovery that a loss of either 120Vac Vital Bus, VIAC-1 or VIAC 2, would cause the inoperability of all four channels of the 90% degreded voltage detection instrumentation. Further review of the ACR tevealed that the. was a specific occurrence of loss of Vital Bus VIAC 1 for two minutes on March 27,1968. Loss of either Bus VIAC-1 cr V AC 2 in Modes 1,2,3, or 4 is specifically addressed by TS 3.8.3.1 Action b(1) which requires re energization within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. TS 3.3.2 Functional Unit 8 b requires three 4kV bus undervoltage gr;d degraded voltage channels per bus to be operable in Modes 1,2,3, and 4. The LCO associated with TS 3.3.2 Functional Unit 8.b is not met when there are no operable 4kV bus undervoltage grid degraded voltage channels I
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on one bus. Thus, the loss of Vital Bus VIAC 1 or VIAC 2 would require an entry into LCO 3.0.3 on the basis of not meeting LCO 3.3.2 Functional Unit 8.b.
The licensee's corrective action for this LER was to revise the Abnormal Operations Procedure AOP 3564 to require entry into TS 3.0.3 upon a loss of Vital Bus VIAC 1 or VIAC 2. The inspector reviewed Revision 7 of AOP 3564, dated 7/28/97, and noted that action statements for entry into TS 3.0.3 were incorporated on page 5.
c. Conclusio01 The inspector verified the corrective action described in the LER was reasonable and complete. Since this violation of the Technical Specification was self identified by the licensee staff and corrective actions were implemented in a timely manner, discretion is being exercised under the Enforcement Policy, Section Vll.B.1and , LER 50 423/97-025 00 is considered closed.
E8.2 eel 50-423/96 20139: Turbine Driven Auxiliarv Feedwater Pumo Calculational Defic 19anies (Update SIL ltem 79)
a. 10ggetion Scoce (92903)
The failure to use the correct turbine exhaust pressure in a design calculation for the turbine driven auxiliary feedwater pump (TDAFWP) was identified as an apparent violation of 10 CFR Part 50, Appendix B, Criterion lil, Design Control", and is eel 50 423/96 201-39. The inspector reviewed the licensee's corrective actions taken to address the calculational discrepancies and to improve the design control process,
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b. Qbittyations and Findinas In order to. validate _the operability of the TDAFWP, the inspector reviewed relevant sections of the Unit 3 Updated Final Safety Analysis Report (UFSAR), Desl0n Basis Data Packages (DBDPs), Emergency Operating Procedures (EOPs), and EOP Setpoint Documentation, in this effort the inspector reviewed EOP 35 ECA 0.0, Revision 11, which delineates the required operator actions for the TDAFWP in response to a loss of all ac electrical power,its associated EOP Setpoint Documentatico Calculation W3 517 981 RE, Revision 4 and the calculational basis for the setpoint documentation, Calculation 91-074-324M3, Revision O. The inspector concluded that the value used for the turbine exhaust pressure, in the latter calculation, was incorrect and nonconservative. Further, the inspector roted that the licensee was advised of this deficiency with a 1983 contrector calculation but performed no further evaluations. The f ailure to use the correct turbine ,
exhaust pressure in Calculation 91074324M3 was considered an apparent violation.
ACR 13426 was initiated to address the noted calculational deficiencies. However there was no closure dur4 the May 1996 inspection. The review of this licensee evaluation was considered URI 50.*')3/96 201 40. As documented in NRC IR 50-423/97 202, the
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new calculations, completed on 3/15/97 and 4/2/97, appropriately rest,1ved the identified deficiencies. Based on these findings, the subject URI wcs closed.
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- 74 i NRC IR 96 201 identified five apparent violations of 10 CFR Part 50, Appendix B, Criterion ,
) 111, " Design Control", for escalated enforcement action. These included Eels 423/96 201 !
- 09,15,35,37 and 39. ACR M3 96-0923 was issued to assess the root cause for these design control f ailures and to develop corrective action plans to address the identified ,
l deficiencies. The root cause and corrective action plans for these issues were included in !
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the licensee's Common Cause Assessment of Apparent Violations, dated 12/13/96. The l common causes cited for design control deficiencies were inadequate: management .
control, corrective action program, work oversight and control, and engineering design and !
configuration control. These common causes are fundamental to the design control process ,
i and are being addressed in a broad ongoing program. A discussion of two completed l elements of this program, the DCM and the revised corrective action program, is provided :
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in the update to SIL 15, in this report, ,
For each eel, the licensee also identified corrective actions which impact directly on the
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issue and/or are issue specific. For the subject eel, these include: the vendor interf ace section presented in the DCM, the preparation of a replacement t alation for Calculation
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91074 324 M3 and the performance of a calculation review effor s part of the licensee's l 10 CFR 50.54(f) response. *
[ As noted above, the replacement calculations for Calculation 91074 324 M3 were
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reviewed by the inspector to close URI 423/96 20140. The new calculations correct the i
deficiencies noted in the original calculation and provide an adequate basis for the
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evaluation of TDAFWP performance. The revised estimates of performance show that the 1 turbine / pump unit can meet design flow / power requirements. The affected unit performance specifications were corrected to reflect the revised performance parameters.
The inspector reviewed Chapter 8 of the DCM titled * Engineering Vendor Interf aces". This
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chapter of the manual provides a framework for interf acing with engineering vendors to maintain the desired level of control of engineering services. The chapter includes specific j requirements to review design documents to assure that applicable design inputs were used and the results are reasonable. Details of specific actions that must be taken to resolve design issues, including the requirement to %rmally communicate any lack of compliance with design conditions, are provided. This formal communication requirement would allow any design deviations to be easily scrutinized by impartial reviewers. This process would '
emphasize the need for additional evaluation and allow early recognition of missing performance data. F tther, the communication requirement would make all design compliance issues a matter of written record. The inspector considered the contents of DCM Chapter 8 an acceptable enhancement of existing vendor / contract control requirements.
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The inspector reviewed the procedure " Assessment of Critical Calculations", Revision 2, and the list of active calculations that resulted from its application to the auxiliary feedwater (AFW) system. The procedure requires the categorization and graded review of calculations within the scope of the DBDP It provides instructions for the categorization and a checklist to f acilitate the graded review. For calculations which verify the capability of a system, structure or component, to perform in accoidance with assumptions used in 2-
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plant accident analyses, or to support the plant TS, (Category Al a verification of the calculational results must be made either b) comparison to test results or through detailed review. For the lesser categories, B and C, a graded reduction in the level of review is required. For all categories, only a checklist documentation of review results is required, On 6/0/97 the procedure was superseded by procedure U3 Pl.31, " Assessment of Millstone Unit 3 Critical Design Basis Calculations".
The inspector considered the assessment procedure to be logical and easily used. However it lacked a requirement to use a quality review procedure to perform and document the detailed reviews. As written, the only documentation of an acceptable calculation is a check mark in the satisfactory box. This provides no indication of the scope or method of the revir' nor the traceability of the review, which may have been extensive, or its results. A requirement to adhere to a recognized, formal, review and documentation procedure would enhance the procedure and ensure compliance with 10 CFR 50, Appendix 0 Criteria Ill and XVil. Procedure U3 PI 31 does not change the review requirements.
c. Conclusions The actions taken by the licensee to address the calculational discrepancies are considered acceptable. The replacement calculations correct the deficiencies that were identified and provide an adequate basis for the evaluation of TDAFWP performance. The vendor review procedure. * Engineering Vendor Interf aces", and the ongoing assessment of critical calculations, are both considered reasonable methods for improving the design control process. They should improve the quality of the calculation databases by providing assurance that they are compreherwive and correct.
eel 90 201-39 remains open pending NRC considerations of potential escalated enforcement actions involving this issue and licensee completion of efforts to improve the design control proceso. Sllitem 79 is hereby updated.(IS THE SIL CLOSED AND THE eel OPEid?)
E8.3 1 Closed) LER 50-423/96 003 00: Temocrarv l-Beams Over RSS Heat Exchanaers (Update SIL ltem 33)
a. inmection Scope (92EQ2J Procedural controls, management attention and worker awareness of the requirements for the proper storage, restraint, and use of temporary equipment within the plant have been the subject of numerous recent ACRs, the subject LER, and IFl 50-423/97 0107. The inspector reviewed the LER, the associated Condition Reports and the licensee's response to the IFl for root cause and the adequacy of corrective actions.
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b. Observations and Findings NRC IR 96 201 identified the concern of I beams with non permanent anchorages installed above recirculating spray heat exchangers and valving. The beams had the potential to render one heat exchanger in each train inoperable and to breach the containment during a seismic event. An imrnediate engineering review by the licensee determined that the beams had been in place sinct 1991 and LER 50 423/96 003 00 was issued. The presence of the beams was due to inadequate guidance given to plant workers on the use of temporary equipment The corrective actions included immediate removal of the beams, walkdown inspections of all safety related areas, revision of work control procedures to provide requirements for temporary equipment and the training of workers on the revised procedures. The inspections revealed other instances of improperly restrained, temporary equipment in safety related areas and resulted in the issuance of four additio..al ACRs.
One year later, in the performance of a Work and Test Control Audit, a licensee team reviewed corrective actions related to LER 96-003 00 and performed audit walkdowns of safety related areas. The audit finding was that the corrective actions ennsidered in the LER had not boon implemented. The audit inspection revealed new instances of improperly controlled temporary equipment and additim d ACRs specifying new instances, further supporting the audit finding. Subsequem PM4dbns into the problem determined that the LER corrective actions had been implem ga nut were inadequate and or incomplete.
In response, an assessment of root cause was conipleted and a revised and expanded corrective action plan was developed. The new plan recognized and addressed
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management's complacency and the informal training, lax scheduling, and ineffectual revision to procedures associated with the original corrective action plan Further, on May 6,1997, a work stand down was instituted to heighten worker and supervisor awareness of the importance of the proper control of tempo.ary equipment in the plant and of the Millstone maintenance and work procedures that address temporary equipment, c. Conclusions The licensee's actions taken in response to their own negative audit finding have given the issue of controlling temporary equipment in the plant an appropriate level of importance.
The root cause assessment is comprehensive and properly recognizes management's complacency as contributing to the inadequacy of the original corrective action plan. The revised corrective action plan is extensive and addresses both the root cause issues and the deficiencies of the original corrective action plan.
The corrective actions are being implemented and will continue to be monitored as IFl 50-423/97 01 07 and in the assessment of closure of CR M3 97 0850. The issue and corrective actions are being addressed in these expanded licensee activities and LER 96 003 is considered closed; Sllitem 33 is hereby updated.
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E8.4 (Undate) eel 50-423/96 08 15: Letdown Heat Exchanaer leakaos and Desian Djscrepancias (Closed SIL ltem 15)
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a. insoection Scone (92903) ,
, t l As documented in IR 50 423/96 06, the licensee's failure to correctly translate the
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technical requirements of the ASME code, relating to the consideration and use of j replaceme.d stud material, into the design details for a design change (Plant Design Change [
Record MP3 90 243) of the letdown heat exchanger, is considered an apparent violation of i- 10CFR50, Appendix B, Criterion 111 for Design Control, eel 50 423/90 0615. The '
inspector reviewed the licensee's root cause assessment, the revised Corrective Action
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Program procedure and the revisions to the Design Control Manual. :
i b. Observations and Findinon -
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ACR M3 96 0971 was issued to assess the root cause of and to develop corrective actions to address the design control f ailure identified as eel 50 423/96 0615 ACR M3 96 0159 ;
was issued to resolve the flange leakage problem that was the focus of the deficient design l
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effort. As documented in NRC IR 50 423/97 202, the licensee's corrective actions to resolve ACR M3 96 0159, letdown heat exchanger replacement and design engineer training, were deemed appropriate. The ACR was considered closed with IFl 50 423/97-202 07 opened to track performance testing and final documentation. The inspector reviewed the corrective actions completed by the licensee to address the design control deficiency, '
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The licensee included the subject eel in the Common Cause Assessment of Apparent
' Violations, dated 12/13/96, prepared in response to the mariy appsirent violations identified by the NRC, Based on that assessment the licensee has undertaken corrective actions to 1 improve the design control process Although these corrective actions are still ongoing, two which impact the subject eel are complete. These are the revised Corrective Action Program and the revisions to the Design Control Manual. ,
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Ineffective corrective actions were cited as one cause of the design control deficiency. -
The licensee established a Corrective Action Manager, with a supporting staff, and revised the Corrective Action Program procedure to improve the corrective action program. The inspector reviewed the latest revision of the Corrective Action Program procedure, it
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clearly delineates the responsibilities of the corrective action department which essentially follows each identified problem throughout the process, This includes ensuring ownership and the assignment of proper significance for each item, preparation for multi discipline management review of the evaluation and corrective action plans, and maintenance and
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processing of an issue database to trend corrective action activities.
The inspector discussed the Corrective Action Program with the corrective action manager
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for Unit 3. He was formerly an acting operations manager for a nuclear plant and has a staff of over fifteen personnelincluding a former operations manager, engineering manager and l&C manager, two senior engineers and two root cause specialists. The inspector
- _ reviewed the quarterly trend report for the first quarter of 1997, issued by the corrective -
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! action department. The report was concita, binned errors by work process, key activity, l I
[ organizational and programmatic failure modes and human error modes, and provided discussions of problem areas / areas of concern based on issue trending. The inspector i
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attended meetings at which the management review team reviewed issue significance level ;
assignments and condition report evaluation / corrective action plans. The meeting l attendees interacted positively to form a consensus in the assignment of significance l
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levels, and to assure that corrective action plans were appropriate and addressed the ;
causal f actors.
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l The inspector reviewed both Revision 4 and Revision 5 of the Design Control Manual (DCM). The majority of the changes could be categorized as either providing clarification to I
- the existing text or specifying new or edditional requirements in the design process. The r J licensee prepared summaries of revisions state: 50.54(f) configuration management revi.ws of all DCM chapters and processes and Nuclear Oversight review comments have
been included. Additionally, the conduct of Safety Evaluation Screenings and Safety [
- Evaluations are referred to Nuclear Group Procedure (NGP) 3.12, and the formal transmittal .
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- of design documents is generally required to comply with NGP 5.03. Tables of contents have been added to each chapter and the manual allows feedback to clarify the intent of wording and processes. The inspector found the manual to be clear and understandable with logical descriptions of process requirements. However, since the inspector was not y
- making actual use of the manual, no assessment regarding the appropriateness and
- completeness of the material was made. ;
l c. Conclusions :
Revisions to the Corrective Action Program and Design Control Manual were considered enhancements and should have a positive impact on the design control process. In ,
particular, the establishment of the corrective action manager with an experienced staff
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provides a level of impartial and knowledgeable oversight to the process that was missing -
} in the former program. This group follows each CR from initiation to closure. It assures a
- clear designation of CR ownership, the assignment of significance levelin accordance with ,
a consistent and logical safety bases and the specification of corrective measures which i are commensurate with CR significance level and causal factors. These were reccgnized ,
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i areas of weakness in the former program and the oversight group provides an appropriate
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method of resolution.
The DCM provides detailed descriptions of most design activities. It delineates responsibilities and formalizes individual design processes. Compliance with the manual should improve the quality and consistency of design activities and documentation. The latest revisions clarify the requirements further and were considered beneficial.
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The licensee is taking actions to improve the design and design change processes. This effort is still ongoing. - The inspector considers the actions already taken to be appropriate.
While the corrective actions and improvements merit that SIL ltem 15 be closed; and the technicalissues on this item have been addressed, eel 50-423/96 0615 is updated, but '
remains open pending _NRC considerations of escalated enforcement action involving this l' issue and licensee completion of its efforts.
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E8.5 Eauloment Environmental Qualifiedpn (EQ) Prooram (92903)
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E 8.5.1 Environmental Qualification Prooram Procedures Review (Closed . SIL ltem 61)
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U.te of_ *DBE 50'C eaavalent life" a. jnsagstion Scone
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The licensee has been revising the environmental qualification (EO) program documentation l since 1994 for all three Millstone units. The inspector reviewed the EQ program manual j and implementation procedures to assess the control and implernentation of the new EQ
program, i
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b. Observations and Findinos ;
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The licensee developed an EQ program in the 1980's to meet the requirements of 10 CFR 50.49. The existing program was reviewed by the NRC during a March 1988 inspection i and was determined to be acceptable. This program used an individual EQ file to demonstrate the qualification of each equipment type. Each EQ file was independent,
- containing system component evaluation work (SCEW) sheets, qualification evaluations, and supporting test reports. The licensee determined that the old program contained too many documents, and was cumbersome to work with when a small portion of the EQ requirements needed to be revised.
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! New EQ Prooram The now program, which the licensee stated would be completed by August 14,1997, for Unit 3, used a much simpler approach. For each equipment type, an equipment _
4 qualification record (EOR) was generated to dccument its qualification. The EQR contained the SCEW sheets, equipment qualified life calculations, and maintenance and replacement a requirements. The test reports that were used to support the qualification were shared by multiple equipment types for all three units, and were not part of the EOR. The licensee referenced in the EQR the appropriate test report assessment (TRA) package, which contained the test reports for the equipment qualification.
. The inspector reviewed four EQ files that were documented using the old EQ program, and four EORs and associated TRAs that were documented using the new EQ program. The .
inspector agreed that the EOR documents were simpler to prepare and easier to audit.
Review of EQ Prooram Procedures The new EQ program for Unit 3 was described in the licensee's EQ program procedure,
" Electrical Equipment Qualification Program Manual," Revision 1, dated March 31,1994.
The licensee used four implementation procedures (program instructions) to implement the program, These procedures were:
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PI 5.1: Instructions for Equipment Ouclification Records (EORs)
PI 5.2: Instructions for Test Report Assessments (TRAs)
PI 5.3: Instructions for EO Calculations and Analyses PI 5.4: Instructions for Equipment Qualification Review of Design Changes The inspector reviewed these procedures and noted the following:
Attachment 8.4, " Test Profile Validation" to Procedure PI 5.3, discussed post accident operating time extrapolation. The procedure states, "For temperature, the thermal aging associated with the demonstrated test profile is compared to the required plant accident profile using Arrhenius methodology. Each profile is extrapolated for an equivalent life at a constant 50'C temperature. This extrapolated time period is called the DBE 50'C Equivalent Life."
Procedure PI 5.3, Section 8.0, defined "DBE 50*C Equivalent Life" as follows:
"The DDE 50*C Equivalent life is the time of equivalent aging occurring during the test, which would occur at a steady state temperature of 50*C. The equivalent life of both the required accident profiles and the demonstrated test profiles are calculated to a single base temperature,50*C, so that they may be compared on eque' terms."
Attachment 9.2, " Assumption and Methodology of EO Calculations," to Procedure PI 5.3, discussed the calculations for test profile extrapolation, stating that the test profile should not be taken into account for post accident extrapolation during the first hour of the test, in the " Methodology" section of Attachment 9.2, the licensee also prescribes a method of applying the "DBE 50*C equivalent life" to a test duration, where the test temperature was continuously changing (negative ramp function). The licensee divided this duration into 75-100 intervals and used an integration method to apply the DBE 50'C equivalent life" for post accident time extrapolation.
The inspector asked the licensee for the basis of the above usage and assumption, but no valid basis was provided during the inspection.
The inspector had three concerns with the above usage and assumptions:
(1) Since the tested temperature profile was divided into many (75100) short intervals, the engineers could have unknowingly used this DBE 50'C equivalent life method for some intervals to extrapolate higher temperature with shorter duration instead of extrapolating longer duration with higher temperature; (2)- There were no NRC rules or technical guidance for using "DBE 50*C equivalent life" for post accident operating time extrapolation, especially for the duration just one hour into the test. In many cases, the temperature at that time was still at the peak level, and had not yet stabilized. The validity of this
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4 assumption was questionable, because there were insufficient test data that could be provided by the licensee to demonstrate that this usage was conservative; and (3) The use of the Arrhenius equation was for constant temperature only. Its use for cases where the temperature was continuously changing (negative ramp function) must be supported by test data to demonstrate its validity. Such test data was not available at the time of the inspection.
In response, the licensee stated that the program procedures would be revised to address the above concerns. On July 24,1997, thu inspector was provided a "draf t" copy of Procedure PI 5.3 (Draf t Revision 3). Section 3.3.1, " Profile Enveloping," of the revised procedure states:
"The test profiles for EQ devices located in a specific harsh zone are plotted
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and super imposed over the postulated plant accident profile. Qualification of equipment for use in harsh temperature environments requires that the tested temperature conditions envelope the postulated plant accident temperature conditions for the post accident duration during which the equipment must function. Any deviations must be justified."
The inspector agreed that this provision would address Concern #1, item 3 of Section 3.3.2, " Post-Accident Operating Time," of the "draf t" procedure states:
"The application of Arrhenius methodology in determining cost-accident operating time is only valid when comparing the latter po'tions of the test and plant temperature profiles using the following criteria:
1. Af ter 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
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2. The profiles are in a non-transient state (i.e., temperature is
' decreasin0 or in a steady state condition), and 3. The tested temperature conditions envelope the postulated plant accident temperature conditions for the post accident duration used in the analysis.
Any deviations from the above criteria must be justified on a case by case basis."
The inspector agreed that these criteria were reasonable for this application, and that they would address Concern #2,
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Item 3 of Section 3.3.2 of the revised procedure also states:
- The use of Arrhenius methodology to compare transient conditions is not -
acceptable because of the difficulty in establishing exactly how much accelerated aging a given device actually experiences during transient -
temperature conditions such that short test durations at high temperatures can .
dominate the exponential Arrhenius relationship and yield non-conservative i
results.
Acceptable qualification requires clear identification of which portions of all profiles are being extrapolated. Only steady state conditions are considered, with down sloping portions of the profile modeled as steady state using the -
lowest temperature of the downward slope at the time the down slope occurD." ;
i The inspector agreed that this provision would address Concern #3.
Since the existing EQ program procedures had been in place for a long time (since ,
- March 31,1994), some EO documents might have been completed using the existing
= program procedures. Therefore, the inspectof considered this issue to be an unresolved item (URI 50 245,336,423/97 203 09) pending: 1) the licensee's formalissuance of the revised program procedures, including Procedure Pl 5.3; and 2) licensee's actions to provide reasonable assurance that all EO documents using the criteria in the existing program procedures for post accident operating time extrapolation have been updated using the criteria as described above. The insnector noted that this issue affects all three units. ;
c. Conclusions The licensee has been revising their EO program documentation. The original EQ files would be replaced by EORs and test report assessments (TRAs). Based on the review of completed EORs and associated TRAs, the inspector concluded that the EOR documents were easier to prepare and update, and that the qualification documents were easier to audit.
The inspector's review of the EQ program procedures indicated that the licensee had used ,
"DBE 50*C equivalent life," based on Arrhenius equation, in its EO calculations for post-accident operating time extrapolation (PAOTE), without providing a sound technical basis for its use. The inspector raised three concerns for this application during this inspection.
The licensee later provided a preliminary version of the revised procedures for the inspector's review. Th6 inspector concluded that the criteria prescribed in the "draf t" proWures would address the inspector's concern. However, this issue is considered an unresolved item pending licensee's issuance of the final version of the procedures and implementation of these procedures into the EO program. This issue affects all three units.
With respect to the Unit 3 EQ program, considering that the above unresolved issue will be tracked as an open item, inspector review of SIL ltem 61 has determined that it is closed. i
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E8.5.2 Review of EO related Adverse Condition Reoort (ACR)
a. insoection Scone The inspector reviewed ACR M3 96 0638, "3SWP'PS152A/B Not On EQ Master List,"
dated August 28,1996 to assess the adequacy of the licensee's corrective actions for resolving this adverse condition.
b. Observations and Findinas The adverse condition was identified by the licensee during an EO walkdown in August !
1996. The two pressure switches (3SWP'PS152A/B) were used to measure the suction pressure of service water booster pumps,3SWP'P3A/B, and to trip the pumps on low pressure. The two booster pumps were required to provide the additional head necessary to circulate service water through the motor control center and rod control area air cooling units during a loss of offsite power or under accident conditions when normal chilled water supply was not available. The pressure switches were ASCO, Model SB21 AICR switches with models TE and TD pressure transducers, Historically, the licensee thought that these switches were located in Zone CW-01, which was a mild environment area. Therefore, they were not on the EQ master list. During the August 1996 EQ walkdown, the licensee four.d that these switches were actually located in the Auxiliary Building Zone AB 33, which was a potential high energy line break (HELB) environment.
Subsequently, the licensee generated ACR M3 96 0638, and issued DCN DM3 00 0940 97 to add these switches to the EQ master list, and to environmentally qualify these switches to the HELB brah environment.
The inspector reviewed the design change package, which included the equipment qualification record (EOR), for the two affected switches. The EOR referenced a test report assessment, TRA 230.0, for the qualification test of ASCO pressure switches. The inspector verified that the tested temperature profile enveloped the accident (HELB) profile, and that the post l ')CA operating time extrapolation was based on the new criteria (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> into the test). Thus, the licensee had demonstrated the environmental qualification of the switches. However, before June 1997, the qualification for these two pressure switches was not demonstrated because no qualification documentation was available.
This was in violation of 10 CFR 50.49, items (f) and (j), which require each item of electric equipment important to safety to be qualified and the qualification record maintained in an auditable form. However, this licensee-identified and corrected violation is being treated as a non cited violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev.
c. Conclusions Tha inspector concluded that the licensee had provided sufficient documentation to r;emonstrate the qualification of the two pressure switches. However, before June 1997, the qualification for these two pressure switches was not demonstrated because no qualification documentation was available. This was in violation of 10 CFR 50.49, items (f)
and (j), which require each item of electric equipment important to safety to be qualified
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l and the qualification record maintained in an auditable form. However, this licensee- i identified and corrected violation is being treated as a non cited violation, consistent with Section Vll.B.1 of the NRC Enforceinent Policy.
Another inspector reviewed the subject ACR to evaluate the licensee's evaluation process for the "reportability" of the identified deficiency. Since the subject switches were in fact EO qualified, the initial determination that na operability concern existed was correct.
Therefore, the initial reportability determination of "not applicable" was validated by a <
subsequent review of the available EO records.
E8.6.3 Post Accident Samolina System (PASS) SOV not functional nost LOCA a. jngnetion Scoce i
Condition Report CR M3 971699 was issued in response to a Unit 2 adverse condition !
report, ACR 7923, which addressed a significant EO lssue identified by the licensee in 1996. The inspector reviewed the process and resolution for CR M3 971699 to determine whether the resolution and associated corrective actions were appropriate. This issue was specifically referenced in SIL ltem 61, which was closed in Section U3 E8.5.1 of this report, b. Obiervations and Findinas Bulgtound Unit 2 ACR 7923 was !ssued on March 26,1996, to address a significant EO deficiency at Unit 2, that seven in containment solenoid valves were found (by the licensee) unqualified ;
for the harsh environment. The licensee attributed the root cause of this EO deficiency to
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be a f ailure to ensure that the EO covered the post LOCA functional requirements.
Subsequently, the licensee generated a Unit 3 Condition Report (CR M3 971699) to determine if similar conditions existed at Unit 3,i.e.,if any solenoid valve's EO did not cover post accident functional requirements.
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The inspector's review of the CR M3 971699 packa0e revealed that the licensee had ~
performed an extensive review of this issue Their review was documented in engineering ,
evaluation report, M3 EV 970123, " Engineering evaluation for determining if additional
. environmental seals are needed based upon SOV post accident operability requirements,"
Revision 0, dated June 19,1997.
As a result of this review, the licensee identified that eight solenoid valves (3 SSP *SOV1 A, 18,1C,1D,2A, 2B,3, and 5) inside the Unit 3 containment were not environmentally qualified because no environmentally qualified seats were used for elecHeal connections.
These solenoid valves were used as the sample selection and sample return for the post-accident sampling system (PASS), which was a nonsafety-related system. The licensee also observed that the safety evaluation report (SER) for the PASS stated that: "The PASS valves, which are not accessible after an accident, are environmentally qualified for the- ,
conditions in which they need to operate." The lice 7 sin 0 department for Unit 3 stated that
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this SER statement was a mistake, because these volves were never meant to be environmentally qualified. The licensee stated that they would submit a letter to the office of NRR to clarify their position. Other than this SER statement issue, the licensee
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considered CR M3 971699 closed.
Baylew of CR M3-971099 M3 EV 970123 contained a memorandum from D. J. Parker of Safety Integration and Analysis te D. Hayes of Unit 3 Design Engineering. Attached to this memorandum was a list of Millstone Unit 3 solenoid operated volve operability requirements. Page 18 of th;s list identified the operability requirements of 3 SSP'SOV1 A,1B,1C,1D. 2A,20,3, and 5 as: " Valves are in the PASS system lines inside containment. To support operability of the PASS system, these valves must be capable of stroking open and closed following a LOCA/SLB(steam line break)/FLO(feedwater line break) inside containment. Not required following HELB outside containment."
lhese eight solenoid valves were Target Rock Model 81V 001 solenoid valves, which had been qualified by the manuf acturer, as documented in Target Rock Test Report No. 3039,
" Qualification Analysis Report for aging, seismic and accident conditions, Models 81V 001 through 81V 021 solenoid operated globe valves," dated November 0,1981. The
, inspector verified that the test profile enveloped the required post accident profile.
The field wires from the valves to the containment penetrations were all Okonite FMR cable. This type of cable was qualified for in containment use, as documented in MPS EOR SP EE 353. Field wirot / rom the valves to the nearby junction boxes were inside American BOA stainless steel flexible conduit with tight seal fittings. Based on these data, it appeared that these solenoid valves could perform their post accident sampling functions.
However, on a walkdown of six of these solenoid valves on July 24,1997, the inspector observed that none of the junction boxes for these valves had weep holes. Generally, weep holes were required to avoid condensate accumulation which could render the terminations inoperable (due to shorted or grounded circuits). During the inspection, the licensee could not justify that three of these eight valves, as installed, were operable post-LOCA. On a telephone call between the inspector and licensee personnel (including Unit 3 licensing engineer, system engineer, two EQ engineers, and a mechanical engineer), the licensee stated that they would generate a design change to: 1) provide environmental seals to the electrical connections; and 2) drill a weep hole at the bottom of each affected junction box. The licensee also stated that the design change would be completed before Unit 3 restart.
In response to inspector's question (on September 3,1997) whether this issue would be repo' table, the licensee f axed additional documentation that was related to CR M3 97-1699, and a new condition report (CR M3 97 2551) dated August 7,1997, included in this additional documentation was a Northeast Nuclear Energy letter (B16652) to the NRC dated July 31,1997. According to the licensee, this letter was to clarify the SER discrepancy (EQ of the PASS valves) described in the " background" section above.
Attachment 2 to this letter was the licensee's proposed SER statement, which states: "All remotely actuated PASS isolation valves that are not accessible af ter an accident are
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designed to tunation under pressure, temperature, and radiation conditions which they will encounter " and "The PASS valves have been designed for the anticipated post accident environments, but are not included in the environmental qualification program."
On o telephone call between the inspector and licensee personnel (including two Unit 3 licensing engineers, two EO engineers, and two mechanical engineers), the licensee agreed that three (3 SSP *SOV10,20, and 3) of the eight PASS valves did not meet the licensing basis. The licenseo stated that the reportin0 of this issue was covered in LER 96 036, Supplement 2, dated July 25,1997. The inspector's review of this LER supplement revealed that, although the LER supplement also included six PASS solenoid valves, the issue was entirely different (mis positioning of the valves could degrado emergency core cooling system performance).
This item is unresolved pending: 1) the licensee's completion of an evaluation to determine the reportability of this issue; and 2) the licensee's completion of tha modification of those ei0ht PASS solenoid valves. (URI 50 423/97 203 10)
c. Conclusion The inspector concluded that the licensee provided an extensive evaluation for the Condition Report. However, the licensee's verification process f ailed to include a walkdown of the identified solenoid valves to ensure that these valves met the operability requirements. An unresolved item involving two licensee actions vsas identified: 1)
licensee's completion of evaluation to determine the reportability of this issue: and 2)
licensee's completion of the modification of these eight PASS solenoid valves.
E.8.5.4 Review of Unit 3 EQ Proaram Self-Assessments a. Inanection Scops The inspector reviewed two licensee assessments of the Unit 3 EO program to determine the adequacy of these assessments, b. Qhsstyations and Findinns in early 1997, the licensee hired five auditors from Southern Company Services, Birmingham, Alabama, to perform an audit of the Unit 3 EO program. The audit results were documented in an engineering self assessment report ESAR PES-97-005, dated April 12,1997. The audit plan was based on Millstone Procedure NUC Pl 21, " Engineering Topical Area Review," Revision 1, dated January 16,1997.
The inspector reviewed both documents and determined the audit to be extensive, covering various areas of the Millstone Unit 3 EO program. The audit identified approximately 25 programmatic type issues in the areas of EO program procedures and instructions, licensing commitments, and EO organization and trainin0. Subsequently, the licensee issued CR MS-97 1055 to document and track the resolution of the identified deficiencies, in this Condition Report, the licensee categorized the 25 issues into 15 items in the tracking
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system. Eleven items were considered by the licensee to be startup issues, requiring resolution before Unit 3 startup. The inspector determined the licensee's tracking for the closure of these items to be adequate, in addition to the above self assessment, the Nuclear Oversicht Group also conducted a Quality Assurance audit from May 12 23,1997, on the EQ program for all three Units.
The audit results were documented in Audit Report M197 A05 02; M2 97 A05 03: M3-97 A05 04, dated May 30,1997. The inspector reviewed this audit report and also interviewed one of the auditors. The inspector found the auditor to be knowledgeable in the areas covered by the audit, c. Conclusions The inspector concluded that the licensee had completed extensive audits on the Unit 3 EO program, covering all major area of this program. These audits resulted in many good findings, which required resolutic.ns before startup. The inspector determined the licensce's tracking for the closure of these items adequate.
E8.5.5 Review of EQ Master List and Qualification Documents of Power rad 2a Meutron Detectors a. Insocction Scoco The inspector reviewed the Unit 3 EO master list (EOML), SP M3 EE 0353, Revision 2, dated February 28,1997, to determine whether it met the technical requirements of the EQ pro 0 ram manual and the regulatory requirements of 10 CFR 50.49. The inspector also selected a sample (power range neutron detectors) from the EOML for a detailed review to determine its EO adequacy, b. Obsg.rvations and Findinos Unit 3 EOML SP M3 EE 0353 was compiled to meet the requirements of 10 CFR 50.49, item (d). The technical requirements of the EOML were prescribed in Section 4.1.4 of the EQ program manual. The licensee stated that the EOML was updated periodically to incorporate new information due to design changes. The inspector's review of the EOML did not reveal any deficiencies. The inspector determined that the EOML fulfilled the requirement of 10 CFR 50.49, item (d).
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During the review, the inspector noted that the eight power range neutron detectors, 2NMP'DET41 A/B; 4?A/D; 43A/B: and 44A/B were on the EOML. The inspector selected this equipment for a detailed review. These eight power rangs neutron detectors (PRND)
were grouped into four detector assemblies (upper and lower detectors) located ex core around the reactor vessel to measure the neutron f%x in the reactor core. On September 14,1979, the NRC issued Information Notice (IN) 79 22 to alert licensees that
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performance of nonsafety related equipment subject to an adverse environment could !
impact the protective functions performed by safety related equipment, including the automatic rod control system. The PRND provided signals to the safety related reactor r protection system, and the nonsafety related automatic rod control system. The concern *
was that following a certain size steam line break inside the reactor containment, the harsh '
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environment caused by the break could cause the PRND to malfunction, due to high leakage current in the potentiallu unqualified connection cable, moving the control rod in an i
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outward direction before the teactor trip. The outward motion of the control rod could have an adverse effect on the departure from nucleate boiling ratio (DNBRh The condition i j for a DNBR less than 1.3 had not been analyzed for Unit 3. During the inspection, the ;
licensee provided a Westinghouse document, NS OPLS OPL t 90 547, " Result of analysis of l
steam line break with coincident rod withdrawal at power for Millstone Unit 3," dated
, - September 25,1990, and a table listing the results of a SBRWORD ( a Westinghouse database) analysis. The table was faxed to the licensee from Westinghouse on July 9, 1997. - These documents provided the analysis results of a spectrum of steam line break l'
sizes from 0.1 to 1.6 f t8 in 0.1 f t' increments. The calculated minimum DNBR for a 4-loop plant was 1.694 at a break cize of 0.3 f t8 . Since thia value was higher than 1.3, the ,
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inspector had no further concern.
I c. Conclusions a .
Based on the review of Unit 3 EOML and the technical requirements prescribed in the EO program manual, the inspector concluded that the licensee had provided adequate controls
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of Unit 3 EOML and that the EOML fulfilled the requirements of 10 CFR 50.49, item (d).
The inspector also concluded that, based on the review of Westinghouse analysis, the harsh environment caused by various sizes of steam line breaks inside the reactor l containment would not cause a concern that the DNBR could drop to an unanalyzed condition.
E8.6 Containment Foundation / FSAR Questions (Update SIL ltem 12)(92903)
in Inspection Report 50-423/96 06, several technicalissues were identified that were i associated w!th the Unit 3 containment structure. The following items discuss the closure of these technicalissues.
- E8.6.1 (Closed) URI 50 423/96 04 13
- Determination of correct bearina load of the containment
'- This item pertains to a need for a detailed analysis of the bearing load of the containment to conclusively establish the basic containment design parameters, and to determine if the .
peak load had been accounted for in the seismic analysis, in a letter dated June 6,1996, the NRC staff requested the licensee to submit an assessment regarding the discrepancy ,
betwoon the bearing load value listed in the UFSAR and the actual peak load calculated for the containment structure.
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In a letter dated August 1,1996, the licensee submitted the requested assessment. ;
Although Attachment 1 to the letter did not clearly explain the discrepancy regarding the actual bearing capacity of the porus concrete mat under the containment, the Attachment 2 to the letter in items F.2.c, F.3,4,5,& 6, provided a detailed and technically valid assessment of the peak load and seismic margin against the calculated peak load. This unresolved item is therefore closed.
E8.6.2 [Closedi URI 50 423/90-04 14: Vrdiditv of UFSAR Table 2.5.4 23_
This item pertains to the validity and use of bearing capacity values listed in UFSAR Table !
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2.5.4 23. The licensee has clarified this information by revising the UFSAR table. Tha inspector verified that the July 1996 revision of the table indicated that the bearing value i listed in the table was for static load only. This issue is reso' sed and the unresolved item is considered closed. ,
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E8.6.3 (Closed) URI 50 423/96-04 15: Final OD of containment This item pertains to a need for a formal operability determination for the containtnent structure. Attachment 2 of the licensee's letter of August 1,1996, documented a detailed, technically valid, and acceptable operabil;ty evaluation for the containment structure. This unresolved item is closed.
E8.7 Accendix R Eauioment Testina a. Insoection Scone (92903)
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The inspector reviewed actions being taken by the licensee to ensure that adequate controls are in place to ensure the proper calibration and testing of instrumentation and controls utilized for plant shutdown from outside the control room, b. Observations and Findinaji The equipment required for performing a plant shutdown from outside the control room is specified in several documents. Plant TS 3.3.3.5, " Remote Shutdown instrumentation,"
specifies the limiting condition for operation for remote shutdown instrumentation transfer switches, power, controls and monitoring instrumentation channels. The equipment is listed in TS Tabte 3.3.9 and the surveillance requirements are specified in TS Sections 4.3.3.5.1 and 4.3.3.5.2. TS Table 4.3 6 specifies the channel check and channel calibration requirements for the remote shutdown monitoring instrumentation. Since these instrument surveillances are specified in the TS, there is a specific surveillance procedure utilized for the channel checks and channel calibrations. ,
Procedure IC 3408A02, "Non Technical Specification Surveillance Instruments (Refuel),"
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identifies instruments associated with licensing requirements that are not covered by TS surveillance procedures. Attachment 3 of this procedure contains Appendix R instruments not covered by TS. These instruments are catibrated on a refueling interval and the
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calibration is controlled by work orders, generic l&C component calibration procedures and the instrument loop calibration report (LCR).
As a result of previously identified issues and recent audits and self assessments of the fire protection and Appsndix R programs, the licensee is taking the following actions:
- The Branch Technical Position (BTP) 9.51 Compliance Report is being revised to include a new section to specify operability requirements for safe shutdown equipment.
- The technical requirements manual (TRM)is being revised to add Section I,
"Fl'c Related Safe Shutdown Components." This section will specify surveillance requirements and actions to be taken for a failed or missed surveil lance.
- The surveillance tests are being reviewed to ensur3 that all Appendix R equipment is adequately tested. The need for four new procedures has been identified as well as the need to revise several existing procedures. The new procedures willinclude tests of controls located on the fire transfer switch panel (FTSP) and tests of the alternate Appendix R trar" itters that are connected by mehns of an " umbilical" cord at the FTSP. The changes to existiPO surveillance procedures willinclude steps to verify local control of equipment such as pumps, valves and the emergency diesel generators.
The licenseo plans to perform the additional testing prior to plant restart. The inspector also noted that in addition to the surveillance test improvements, there are numerous other corrective actions being taken in the areas of fire protection and Appendix R.
c. Conclusions The inspector found that the licensee was taking appropriate actions to improve the procedures and controls for Appendix R equipment testing. However, since the affected documents were still being finalized, the effectiveness of this effort could not be assessed at this time. Also, the safety significance of the apparent lack of testing in the past can not be assessed until the required tests are performed and the results evaluated. This item is unresolved pending further NRC review of the final documents and the results of additional testin0. (URI 50-423/97 203 011)
E8.8 LUndate) eel 50-423/96 201-27: Failure to Adeauatelv Co rect Protective Relav Settinas (Update Sllitem 37)
a. Inspection Scoce Q2903)
The inspector reviewed the corrective actions taken by the licensee to resolve discrepancies between the UFSAR, protective relay settings and design documents.
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) b. Observations and Findings During a special NRC inspection of engineering and licensing activities (IR 50-423/96 201), l'
the inspectors identified an apparent violation of the corrective action requirements of 10 CFR 50, Appendix B. The team fo.Jnd that, although aware of inconsistencies of design i criteria for setting protective revs and previously 3dentified discrepancies, the licensee l f ailed to perform a comprehens evaluation of the protection criteria, the FSAR and the installed configuration.
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in response to the team's findings, the licensee performed a complete review of relay .j settings and criteria, and identified the following actions to be necessary to resolve the ;
discrepancies: :
- Revise FSAR Section 8.341.1.4.2 to eliminate design criteria discrepancies: [
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- Revise Specification SP EE 269, " Electrical Design Criteria," to modify design
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criteria and resolve relay setting discrepa..cles;
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- e Incorporate calculation changes in Specification SP EE 321. " Control of
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Electrical Setpoints," and, I
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- Reset the tap setting for the long time inverse overcurrent unit for quench spray (OSS) pump motor 3OSS*P38. .
The licensee has completed actions to revise the affected documents and the OSS relay l has been reset, calibrated and trip tested. The only remaining action is to verify satisfactory operation of the OSS pump during the next start. This retest is tracked by !
work order M3 96 09032.
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c. Conclus12DA '
The inspector found that the licensee had appropriately resolved the specific technical issues associated with eel 96 201 27. However, eel 50-423/96 201 27 remains open pending completion of NRC enforcement considerations. SIL ltem 37 is hereby updated.
E8.9 IUndate) eel 96 201-07: Failure to Evaluate UFSAR Change in Accordance
! With 10 CFR 50.59 (Update . SIL ltem 7P)
i a. jntgection Scone (92903) ,
The inspector reviewed the licensee's corrective actions associated with an apparent violation of 10 CFR 50.59.
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b. Ohs.ervations and Findings The inspection team identified that the setpoint for the emergency diesel generator (EDG)
toom low temperature alarm was changed from 42*F to 52'F to ensure that the room temperature was maintained above the minimum for equipment qualification (50'F).
However, although the setpoint and associated alarm response procedures were discussed in the FSAR, the licensee f ailed to perform a safety evaluation for the setpoint chan0e in accordance with 10 CFR 50.59.
The licensee subsequently performed a safety evaluation in accoraance with 10 CFR 50.59 and concluded that the change was safe and did not involve an unroviewed safety question.
c. CQndusk(1s The inspector found that the safety evaluation appropriately addressed tb5 setpoint change, and no unroviewed safety question was created by the change However, eel 50-423/90 201-07 remains open pending completion of NRC enforcement :onsiderations. SIL ltem 78 is hereby updated.
E8.10 (Closed) IFl 50-423/97 202 05: Safetv/ Relief Valve Testina Inservice Tejidag of Pomos (Update SIL ltem 74)
a. Insanchon Scope (92903)
The inspector reviewed the licensee's actions associated with Sllitem 74, ' Inservice Testing Program Control."
b. Observations and Findings The licensee reported numerous deficiencies associated with the IST program in LER 50-423/96 021 00 and supplement 96 021~01. Subsequent to the issuance of the LERs, the NRC performed an inspection of the IST program (IR 50-423/97 202). The inspector openedIFl 50-423/97 202 05 to track NRC review of the licensee's evaluation of the adequacy of the safety / relief valve test method to ensure that it meets the requirements of the ASME Code and plant TS. The licensee documented the question on CR M3 971758.
The licensee's evaluation included a review of the test methods for both the pressurizer safety valves and the main steam safety valves. The licensee concluded that the valve test methods used by Wyle Laboratories and the hydroset assist method of testing main steam safety velves meet the ASME Code requirements.
The inspector also identified (IR 50 423/97 202) that the licensee needed to provide additional justification for using broader reference valve tolerances (for pump testing) m a relief request to the NRC, or taka other actions to meet the tolerance band required t'y the Code. At the time of this current inspection, the licensee had not completed this
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evaluation. This item remains unresolved pending NRC review of the licensee resolution of the issue. (URI 50-423/97 203 12)
c. Conclusions
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The inspector concluded that the licensee evaluation of the safety valve testing method- ;
adequately addressed the question and IFl 50 423/97 202 05 is closed. SIL ltem 74 is !
updated and remains open pending closeout of URI 50-423/97 203 10. j
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E8.11 (Closed) URI BO-423/96-201 16: Analvsla Related to TDAFW Discharoe
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laulation Valves (Closed SIL ltem 19)
a. Insoection Scoce (92903) !
The inspector reviewed *,he licensee's resolution of a concern that portions of the turbine driven auxiliary feedwa'er pump flow path are exposed to high energy conditions during ;
normal plant startup, hot standby or during shutdown when a motor driven auxiliary feedwater pump is operated. l i
b. Observationa and Findinos ,
The licensee's practice had been to isolate the affected portion of the AFW system when a motor driven AFW pump was operated. However, this practice was found to be a violation !
of plant technical specifications.
l The licensee initially planned to revise the plant TS to permit the use of the AFW system during startup. Following additional review, the licensee decided that the solution to the issue would be to not use the AFW system during normal startup . r shutdown. Instead of using the AFW system, the main feedwater system will be used for normal startups and shutdowns as originally designed. Any necessary procedure changes and training are being tracked by Action Request 97000592 02 and will be completed to support closeout of ;
related Eels 50 423/96 201-04, and -05 (SIL ltem 11). ,
c. Conclusions The inspector concluded that the proposed approach to use the normal main feedwater system will eliminate the need for isolating the turbine driven AFW pump during normal ';
operations. Unresolved item 50 423/96 201 16 and SIL ltem 19 are closed.
E8.12 IClosedLLER 50-423/97-026 00: Missed SWS Sucoort Examinations Reauktd bv ASME Section XI(Update SIL ltem 74)
a. Insoection Scone (92903) ,
- The inspector reviewed the licensee's findings and corrective actions reported in LER 50-423/97 026-00. .
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b. Qhgervations and Findinas j in March 1997 the licensee identified twenty five service water system supports that had [
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not been examined as required by Section XI of the ASME Code. Relief was not requested
- in accordance with 10 CFR 50.55a to exempt these supports from the inspections. Also, one support did not receive a successive inspection as required by the Code, following
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corrective measures, The f ailure to perform the inspections is a violation of TS surveillance
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The licensee subsequently performed inspections of the affected supports and found them to be acceptable. The Inservice inspection (ISI) Program Manual was revised to include guidance on the ASME Code inspection requirements and on the requirements Mr '
requesting relief from the ASME Code, when appropriate. Surveillance procer a
- SP31129, " inservice inspections," was changed to include additional guidancs on the l performance of the inspections. ;
c. Conclusions The inspector reviewed the licensee's inspection results and procedure changes and concluded that this issue was appropriately reco!ved. This licensee identified technical .
. specification non compliance is being treated as a Non Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Poliev. This LER is closed. SIL ltem 74 is j updated and remains open pending resolution of the URI documented in Section U3.E8.10
, of this report.
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IV Plant Silppad (Common to Unit 1, Unit 2, and Unit 3)
R1 Radiological Protection and Chemistr/ Controls R1.1 Radioloalcal Protection Procram a. Insoection Scoce (80750)
The inspector reviewed the licensee's programs for the control of radiological workers, release of potentially contaminated materials from within the units and from the station.
changes to the ALARA program at Uriit 3, dosimetry records and survey instrumen'
calibration. The inspector reviewed 1:censee documents, interviewed personnel. e e o m-direct observations of licensee activi.les.
b. Observatigos and Findinos UBlL1 Since the last specialist inspection in this area,little additional work has been performed in the Unit 1 RCA. Current planning has the unit resuming work on January 5,1998, and to that end an outage plan was released on September 16,1997. The plan still is subject to amendment, and will not be finalized untillate November, but does identify major work activities to be completed prior to the Unit being ready to restart. Based on the identified scope of work both in this outage plan, and on the work postponed from 1997, the licenseo made a rough estimate of 200 person-rem required to complete the work in 1998.
The inspector will further review this outege plan and the resultant ALARA planning during future inspections in conjunction with the closure of Sllitem 16.
On September 8,1997, a radworker entered the RCA through the south turbine building RCA entrance (sometimes referred to as the maintenance entrance) without his electronic dosimetry, as required by a unit RWP. The worker's electronic dosimeter was discovered by a co worker still in the dosimetry reader unit. The co-worker notified health physics which identified who the dosimeter was issued to, and paged the worker to leave the RCA immediately. Failure to follow written health physics instructions is a violation of Unit 1 Technical Specification 6.8. (VIO 50 245/97 20313).
An additional concern is that the worker was utilizing the RCA, specifically the turbine building west walkway, as a travel path to the control room, which is located outside the RCA, on the north side of the unit. Utilizing a posted RCA as a general travel path is contrary to the as low as is ceasonably achievable (ALARA) principle. Discussions between the inspector and the unit Radiation Protection Manager (RPM) indicated that the RPM was equally concerned with the ALARA aspect of this issue. On September 16,1997, a unit stand down meeting was held with all unit staff on site to discuss the radworker compliance issue, and to stress the importance of minimizing exposures.
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i The inspector reviewed documentation and made direct observations of health physics I controttiin place at Unit 2. Specific emphasis was placed on: documentat!on of l radiological surveys, both general area and job specific; control of contaminated areas
within the RCA: and release of personnel and equipment from the RCA. No discrepancier with NRC requirements were identified, and the licensee appeared to be effectively ;
implementing its radiation protection program in these areas.
On Septernber 12,1997, a radworker entered the RCA without his electronic dosimeter, which was discovered to have been lef t in the dosimetry reader located by the main health physics check in point. The worker was paged and instructed to leave the RCA immediately. On September 16,1997, another radworker exited the RCA through door 275, which is specifically posted as an emergency exit only. No emergency existed at the time of this action. This door led the worker out of the RCA, bypassing the personnel monitors. Failure to follow written health physics instructions is a violation of Unit 2 Technical Specification 6.8. (VIO 50 336/97 203A3). ,
UDill j Unit 3 conducted its first ALARA Committee meeting on September 18,1997. The establishment of an AL/.RA Committee had previously been identified (NRC Inspection Report 60 423/97 202) as needed in order to address significant werknesses in the unit ALARA program. The Committee includes the unit director and all roajor department managers. The inspector attended the initial meeting and identified several significant improvements in the ALARA program at Unit 3, including: the establishment of departmental goals for 1998: selection of personnel to serve as ALARA liaisons to each department; and the commitment of senior unit management for the establishment of an i
effective ALARA program at the unt ,
At the time of this inspection, the licensee was nearing the completion of the replacement of all four reactor coolant pumps (RCPs), and preparing for work in the spent fuel pool, to include diving. The inspector observed work in the containment on the newly installed RCP
"D", and preparations for the installation of a new RCP "A" Initial ALARA estimates were for the replacement to expend 24 person-rem, however, due, in part, to lower than '
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anticipated area dose rates, the work completed to date was performed for only 11 person-rom. At the ALARA Committee meeting, the unit director indicated that a revised ALARA goal for 1997 should be established to reflect the lower exposures to date both for this work, and for the unit annual goal.
On September 13,1997, a worker entered the RCA through a door in the ESF building.
The worker was not wearing electronic dosimetry, and had not intended to enter the RCA.
The door utilized was appropriately posted as an RCA entrance. The worker identified his errcr and proceeded immediately to the nearest RCA exit. Entry into the RCA requires workers wear electronic dosimetry in accordance with w."tten plant procedures. Failure to follow written health physics instructiuns is a violation of Unit 3 technical specification 6.8.
(VIO 50 423/97 20313).
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. Site Health Physics l
The inspector reviewed the licensee's dosimetry records system as part of the specialist ;
i inspection. Since 1994, electronic records, in the form of fully retrievable and backed up _ )
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computer data bases, are maintained by the licensee for all workers issued dosimetry. The
inspector selected more than 50 personnel, at random, and reviewed the data base records l 4 for each. All records reviewed were determined to be in full compliance with the applicable i
provisions of Title 10, Code of Federal Regulations, Part 20.
The inspector reviewed the licensee's prograr, for the calibration and maintenance of
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survey instruments utilized in the radiation protection program. The site support health physics organization is tasked with the maintenance and calibration of hand held survey instruments, friskers, personnel portal monitors, and electronic dosimeters. To implement this program, the licensee m:Intains an inventory of radiation sources both for calibration ,
and source checking these instruments. Calibration sources are verified as traceable to the !
National Institute of Standards and Technology (NIST), while a number cf sources utilized
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for the daily or weekly source check program were made from plant smeets so that the
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isotopic concentrations were reflective of plant conditions.
The inspector reviewed the calibration records and source check data on a number of
. instruments, especially those used at Warehouse 9. This facility is where materials that 3- have been used in or near the RCA are surveyed for contamination prior to free release. All
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instrumentation reviewed was determined to be properly functioning, calibrated and source checked. In general, smaller articles are either hand frisked or passed through a 16 unit frisker table, then checked in a small article moniter prior to release. Records to support these activities were available in the health phmes field office located in Building 410. All
activities reviewed were determined to be in compliance with applicable NRC regulations, i
c. Conclusions The program for maintaining occupational exposures as low as is reasonably achievable l'
(ALARA) at Unit 3 showed improvement, especially with the establishment of an ALARA Committee. A very effective program for the calibration of health physics survey a instrumentation was established. Controls established to ensure that materials released from the site are not radiologically contaminated were determined to be effective. A
, recurring violation, however, was identified in the area of radiological worker practices.
There were three examples (one at each unit) of individuals entering the RCAs without
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wearing electronic dosimetry and one event where an individual exited the RCA at Unit 2 i through a door specifically posted as an emergency exit only, and thereby circumvented
- the normal controls for exiting the RCA.
R1.2 Unit 1 Radwaste (Closed Unit 1 Significant items List No. 2)
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a. Insoection Scooe (86750)
The inspector reviewed licensee actions taken following a resin liner temperature excursion
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in 1995. The inspector reviewed a package of licensee documents relating to the event,
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revisions made to licensee procedures following the event, and reviewed a random sample of resin liner processing records since the event.
b. Obiprvations and Findings The inspector was previously apprised of a resin temperature excurs!on event that occurred in 1995 while dowatering of Unit 1 resins in the solid radwaste facility. The inspector was briefed by licensee representatives from waste management and chemistry during a visit in July .1995. During this inspection, the inspector reviewed licensee documentation regarding corrective actions taken to preclude a similar event from occurring again.
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During dewatering operations of a resin liner at Unit 1, a temperature excursion of more than 100*F occurred within the process liner. The liner was subsequently successfully dowatered, and permission was received from the State of South Carolina to dispose of this liner at the Barnwell Low Level waste Management facility. The licensee's .
investigation of the event focused primarily on the possibility of nitrogen compounds being inadvertently introduced into the resins, which might have caused the excursion. The second focus of the licensee's hvestigation was on the thermocouple used to record temperature in the liner. Appropriate functionality and calibration of the thorn.ocouple was completed shortly af ter the event. No attempts taken by the licensee shortly af ter the excursion were successfulin recreating the observed temperature rise. Licensee actions reviewed by the inspector included chenges marie to waste services and Unit 1 operations procedures to ensure against the addition of nitrogen compounds into the spent resin tank, and for the improved monitoring of resin / Water sluice temperatures in the spent resin tank.
transfer lines and resin liner. The inspector had previously reviewed other spent resin processing records (NRC Inspection Reports Nos. 95 35 and 96-08), and determined that no similar temperatu 9 excursions had been documented, c. Conclusions The licensee's investigation of the temperature excursion and actions to prevent recumence were appropriate.
R1.3 Radiolonical Waste Transoortation a. Insoection Scoce (86750)
The inspector performed any in office review related to a licensee shipment of radioactive materials, which upon receipt, was determined to have external radiation levels in excess of regulatory limits, b, Observations and Findings
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On July 25,1997, the licensee shipped to the Connecticut Yankee Atomic Power Station, radioactive materials packaged and classified as a limited quantity shipment, in accordance with Title 49, Code of Federal Regulations, Part 173.421 (49 CFR 173.421). The maximum extemal radiation level permitted in such a shipment, as found in 49 CFR
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173.421(a)(2), is 0.005 milliS; everts / hour (0.5 mrem /hr). Upon receipt at Connecticut !
Yankee, the package was found to have radiation levels as high as 0.01 milliSieverts/ hour
_ (1.0 mrem /hr). - .
c .- Conclusions i
Licensees transporting radioactive material are required by 10 CFR 71.5 to comply with the applicable provisions of the Department of Transportation requirements contained in 49 - .
CFR in.diation levels inr a limited quantity shipment in excese 'of the limit found in 49 CFR i
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173.421(a)(2) is a violation. (VIO 50-245;336;423/97 203 14)
R8 Miscellaneous Rsdiological Protection and Chemistry issues
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. 38.1 1C10&pdl Violation 50-245/96-0918: 50 336/96-0918: and 50-423/96-0918:
, Failure to Use a Pronerivfalibrated lonization Chamber .
This violation involved the failure to use a properly calibrated ionization chamber for Procedure ES#142, "Thermoluminescent Dosimeter Irradiation." As corrective actions, the licensee updated Procedure ES#142 (Revision-11, Effective date: March 1997) to es'ablish .
an annual calibration frequency requirement for the ionization chamber, including the condenser "R" meter. On January 29,1997, the ion chamber (including condenser "R"
meter) was calibrated by the manufacturer, Victoreen, Inc. The accuracy was i2%
(traceable to NIST) which was within the licensee's acceptance criteria (iS% traceable to NIST). _The inspector verified that the licensee: (1) established a technique to monitor the
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constancy on a regular basis; and (2) followed Table #2 (TLD Calibration Factor Method) of rincedure ES#142, as required. The inspector concluded that the licensee's corrective actions had been appropriate. Violation 96 0918 for all three units le closed.
R8.2 (Closed) Insoector Followuo item 50-245/96-13-01: Definina Resoonsibilities -
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to Comolv with Radioactive Liauid and Gaseous Effluent Control Proarams
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- a. Insoection Scoce (929041 The inspector reviewed the corrective actions taken in response to the subject inspector followup item, b. Observations and Findinas.
This item involved defininq responsibilities within the former Chemistry Department and the Radiological Assessment Branch (RAB) to comply with tne radicactive liquid and gaseous effluent control programs. The inspector reviewed the licensee's corrective actions
. (organizations, responsibilities, self assessments) and made the following observations:
e _ Newly assigned chemistry specialists of the Chemistry Department at each unit have the responsibility for ensuring. compliance with the radioactive liquid and gaseous effluent control programs, The Chemistry Technical Support
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100 Group and the RAB are responsib!e for the effluent control programs. The licensee's corrective actions were good;
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- Strengths and areas to be improved (i.e., communications) were assessed by
the Chemistry Technical Support Group and the Chemistry Department staff.
The assessments were very good to enhance the effluent control program; and
- The stability and experience o' the chemistry specialist staff of the Chemistry Oopartment, Chemistry Technical Support Group, and the RAB ior the effluent control program were very good, c. Conclusi QD1 Based on the above observatior's, the NRC determined that responsibilities associated with the radioactive liquid and gaseous effluent control programs were adequately defined. The licensee's corrective actions were very good, inspector followup Item 9613-01 is closed.
R8.3 (Closed) Insoector Followuo item 50 245/96-13-02: Maintainino a Negative Pressure in the Unit 1 Reactor Buildino.
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Section 9.4.2 of the Unit 1 UFSAR, " Reactor Building" requhod maintaining a negative
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pressure. Tiie licensee stated that a negative pressure was maintained in the Rewtor J Building.
The inspector reviewed the licensee's revised procedures (SP 696,1, Control Operators Leg: and SP 696.2, Plant Equipment Operators Log). The inspector also reviewed procedure OPS Form 696.2-2, which contained pressure measurement records for the Unit 1 Reactor Building. Reviewed data ware within the licensee's acceptance criteria ( 0.5 to -
1.5 inches of water). The licensee's corrective act;ons were appropriate; Inspector Followup Item 96-13 02 is closed.
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R8.4 (Ocen) Violation 50 245/96-13-01 (IFS Item 96-13-03): Maintainino a Negative Pressure for the Unit 1 Turbine Building and Steam Tunnel
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As stated in the licensee's response letter to the violation, dated on March 26,1997, and the NRC's letter dated on April 18,1997, the licensee's corrective actions were in process . The licensee committed to the NRC that the corrective actions for this violation will be completed prior to restart. The inspector was informed that about 60% of the corrective actions were completed as of August 11,1997. The inspector stated that the
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corrective actions will be reviewed before restarting Unit 1.
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R8.5 (Closed) Violation 50-336/96-13-01(IFS ltyn 96-13-04): Failure to Establish Adeodate Procedures to Test the Unit 2_ Main Exhaust Svstem HEPA Filter This item involved the failure to establish and implement procedures sufficient to test the
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HEPA filter of the Main Exhaust System [(1) the containment aiid enclosure building purge _
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101 system (L 25); (2) the radwaste area ventilation system (L 26); and (3) the spent fuel pool area exheust system (L-27)],
Procedure SP 26540, " Main Exhaust System HEPA Filtration Testing" (Revision 0, Effective on January 15,1997) was prepared and approved by the Plant Operations Review Committee on January 13,1997. The inspector reviewed Procedure SP 26540, and determined that the procedure was well written to satisfy the requirements. The licensee performed surveillance tests during the first week of February 1997 using Procedure SP 26540. All testing results were within the licensee's acceptance criteria.
The licensee revised Section 9.9.9.4.2 of the FSAR to describe the HEPA test requirement for the main exhaust system. The licensee's corrective actions were acceptable; Violation 336/96 13 01 is closed.
R8.6 (Ocen) Insocetor Followuo item 50-336/9613-01 (IFS item 96-13-05h Unit 2 Turbine Buildina Pressure Section 9.9.12.4.1 of the Unit 2 Final Safety Analysis Report stated that the turbine building was maintained at a slight positive pressure by the area ventilation system to prevent infiltration from the adjacent Unit 1 turbin' building. The licensee issued Engineering Work Request (EWR) 2 96-190 based on their investigation of this followup item. The inspector stated that this item remained open pending the completion of EWR 2-96-190. During evaluations and investigations of this item, the licensee extended their investigation to the control room's differential pressure. Section 9.9.10.3.2 of the Unit 2 FSAR states that "The control room is maintained at or near atmospheric pressure during normal operation. Adjacent areas are maintained at a negative pressure with respect to the-control room to prevent in leakage." The licensee noted that there was no existing instrumentation or method to verify that adjacent areas to the control room were maintained at a negative pressure. On January 21,1997, the licensee issued Adverse Condition Report M2-97-0115 to comply with the FSAR requirements (e.g., differential pressure gauge installation). The corrective actions will be reviewed upon completion of corrective actions and closure of the Condition Report.
S1 Conduct of Security and Safeguards Activities S 1.1 Security and Safeauards Activities a. insocction Scone
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The inrpectors reviewed the security program implementation during the period of July 28 to August 1,1997. Areas inspected included: previously identified items; protected area detection equipment; alarm stations and communication; testing, maintenance and compensatory measures; and training and qualification. The purpose of this inspection was to determine whether the licensee's aecurity program, as implemented, met the licensee's commitments in the NRC-approved security plan (the Plan) and NRC regulatory requirements.
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b. Observations and Findinos Alarm station operators were knowledgeable of their duties and responsibilities and security
. - training was being performed in accordance with the NRC approved training and j qualification (T&O) plan. l l
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Protected area (PA) detection equipment satisfied the NRC approved physical security plan
. (the Plan) commitments and security equipment testing was being performed as required by the Plan < Maintenance of security equipment was being performed in a timely manner as evidenced by minimal compensatory posting associated with non-functioning equipment.
c. Conclusions
. .The inspectors determined that the licensee was generally conducting its security and
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safeguards activities in a manner that protected the station as well as public health and
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safety.
l S2 Status of Security Facilities and Equipment
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S 2.1 Protected Area Detection Aids l l
The int.pectors conducted a physicalinspection of the Protected Area intrusion detection !
systems (IDSs). The inspectors determined by observation and by reviewing testing
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records, that the IDSs were functional and effectivo, and were installed and maintained as j
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described in the Plan.
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S2.2 Alarm Stations and Communications a. Insoection Scooe
The purpose of this inspection was to determine whether the Central Alarm Station (CAS)
and Secondary Alarm Station (SAS) are: (1) equipped with appropriate alarm, surveillance
and communication capability, (2) continuously manned by operators, and that (3) the systems are independent and diverse so that no single act can remove the capability of
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detecting a threat and calling for assistance, or otherwise responding to the threat, as
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required by NRC regulations.
b. Observations and Findinos Observations of CAS and SAS operations verified that the alarm stations were equipped
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with the appropriate alarm, surveillance, and cornmunication capabilities. Interviews with
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CAS and SAS operators found them knowledgeable of their duties and responsibilities. The
- inspectors also verified through observations and interviews that the CAS and SAS operators were not required to engage in activities that would interfere with the
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assessment and response functions, and that the licensee had exercised communications methods with the local law enforcement agencies as committed to in the Plan.
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103 c. Conclusion The alarm stations and communications met the licensee's Plan commitments and NRC requirements.
S2.3 Testino. Maintenance and Comocnsatorv Measures a. Insoection Scong The purpose of this inspection was to determine whether programs were implemented that -
will ensure the reliability of security related equipment, including proper installation, testing and maintenance to replace defective or marginally effective equipment. Additionally, determine that when security related equipment failed, the compensatory measures put in place were comparable to the effectiveness of the security system that existed prior to the failure, b. Observations and Findinas Review of testing and maintenance records for security-related equipment confirmed that documentation was on file that demonstrated that the licensee was testing and eraintaining systems and equipment as committed to in the Plan. A priority status was being assigned to each work request and repairs were normally being completed in a timely manner for all work, necessitating compensatory measures. The inspectors noted that from January 1 to July 27,1997, 528 work orders were generated. As of July 31,1997, only 24 work orders remained open, seven of which were awaiting parts and none requiring compensatory posting, c. C,onclusions Security equipment repprs were timely and the use of compensatory measures was found to be appropriate and minimal.
SS Security and Safeguards Staff Training and Qualification SS.1 Training and Qualification a. Jasnection Scong The purpose of this inspection was to determine vthother members of the security organization were trained and qualified to perform each assigned security related job task or duty in accordance with the NRC-approved training and qualification (T&O) plan.
b. Observations and Firdings The inspectors randomly selected and reviewed T&O records for sixteen security force members (SFMs). Physical and firearm requalification records were inspected for armed
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and unarmed SFMs and security supervisors. The inspectors found that the training had been conducted in accordance with the T&Q Plan, and was properly documented.-
Additionally, the inspectors observed classroom training that utilized the firearms training system (FATS). The training required the trainee to use proper judgement in shoot /no-shoot situations, proper shot placement under stress conditions, and use of cover and-
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concealment. The training aid is an excellent training tool and the instructors provided
- excellent critiques af ter each scenario was completed.
c. Conclusions The inspectors determined that training had been conducted in accordance with the T&O plan Based on the SFMs responses to the inspectors' questions, and inspectors'
observations, the training provided by the security training staff was considered effective.
S8 Miscellaneous Security and Safeguards issues S8.1 (Closed) eel 50-245/336/423/96-0515. eel 50-245/336/423/97-03-03:
Failure to Procerly Control Safeguards Information
Corrective actions, as implemented, were determined to be comprehensive and effective.
These actions should minimize the potential for recurrence of this violation. These violations are closed.
S8.2 (Closed) Violation 50-245/96-09-20: Failure to Control Access to the
Protected Area Corrective actions, as implemented, were determined to be comprehensive and effective and fully implemented. This violation is closed.
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S8.3 (Closed) eel 50-245. 336 & 423/97-03-01: Failure to Perform a Procer Search with a Hand Held Metal Detector
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Corrective actions were prompt, comprehensive and properly irnplemented. This violation is closed.
S8.4 (Ocen) eel 50-245. 336 & 423/97-03-02: Failure to Control Vehicles in the s Protected Area The inspectors reviewed a recently implemented pilot program for control of onsite vehicles. The program, as implemented, appeared to be effective. However, because it had been in place for a limited period of time and not all station vehicles were in the program, this item will remain open until its effectiveness over a longer period can be evs.luated, and all station vehicles are included in the program.
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V. Enaineerina Multiole Units i
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E1 Conduct of Engineering
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E1.1 Vendor Interface Program Review Site Level '
- a. Insoection Scoce (37551)
The overall site program for Vendor Interface was reviewed; comments and discussion that apply to all three units are provided here. The first NRC correspondence related to this area was Generic Letter (GL) 83 28 that was issued after the Salem anticipated transient without scram event.--In response to GL 83 28, the industry developed the NUTAC report INPO 84-010. In 1990, the NRC issued GL 90-03 to modify the guidance from GL 83 28, !
' Item 2.2 and to endorse aspects of INPO 84-010. NU responded to GL 90-03, and the i 4. . NRC approved their commitments by letter dated 5/9/91. In 1995, NU incorrectly canceled
- a procedure that implemented some of the commitments made for GL 90-03. When this was identified, the licensee re-instituted the programs. The current review of the Vendor interface Program is being performed at both the site and individual unit levels in order to-verify that appropriate policies and procedures are in place and are being effectively implemented. The basic guidance being used for the review is GL 90-03 and related documentation.
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b. Observations and Findings There are four main areas from these sources that were reviewed: the program with the nuclear steam supply system (NSSS) vendor, contacts with other vendors (including vendor manual updates),interr.v handling of onsite vendor services, and other activities related to i
INPO 84-010 such as SEE IN. These are each u.scussed below.
1. Etogram with NSSS vendor The inspector discussed the NSSS interface programs with the onsite Nuclear Safety Engineering (NSE) Group and with the three onsite NSSS vendor representatives: General Electric for Unit 1, ABB/ Combustion Engineering for Unit 2, and Westinghouse for Unit 3.
1 Each of the NSSS representatives nave been onsite for some time. They serve as a resource for technical information and the focal point for communication between the
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NSSS home office and the site. They work with many different organizational entities onsite. All correspondence comes officially to the site o>ect from the NSSS vendor home office. NSEG serves as the central group, coordinating new NSSS vendor technical information for all three units.
Tha inspector noted that the following two areas of the NSSS vendor program, described in INPO 84-010, were not completely addressed: the licensee had not routinely verified that they have received all technicalinformation provided by the vendors; and vendor manuals
- _for safety-related NSSS equipment for Unit 1. Regarding the assurance of aceipt of all technical information from the NSSS vendor, af ter a discussion by the inspector with the
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105 licensee, the licensee performed a review and found that NSEG had not received some recent CE Info-bulletins and that recent Westinghouse Info-grams had not been input into the assessment process. The licensee acknowledged that they did not have provisions for such verification and issued CR No. M1-97-1914, applicable to all three units. During the inspection period, the licensee performed a root cause analysis of this issue that determined causes and recommended corrective actions.
Regarding Unit 1 manuals, the inspector noted that, since Unit 1 was a turn-key plant, they do not have vendor manuals for safety-related NSSS equipment. The inspector questioned how Unit 1 would meet the guidance of the generic letter for: NSSS information, updated manuals and vendor information given the current situation. The licensee stated that this would be evaluated as part of the DC 16 Vendor Evaluation Technical Information Program (VETIP).
2. Confacts with other vendors When re-instituted in 1995/96, the program for contacts with other vendors was being conducted by the Procurement Engineering Group (PEG) per procedure PEG 6.05 for all three units. This procedure will eventually be superseded by the new procedure DC-16.
The licensee stated that their intent is to fully comply at the present time with the guidance in GL 90-03. Then over the next 18 months they will further enhance their program by expanding the key safety related equipment list (KSREL) and by implementing a contract with PRC/ USA to perform and enhance their vendor contacts. The inspector reviewed the activities currently being performed by the PEG, including: determination of the KSRELs, development of vendor lists, contacting of vendors, actions when vendors go out of business, and handling of vendor responses. The inspector reviewed the information for both the 1996 and 1997 cycles of vendor contacts.
The following issues were noted from the above reviews:
- PEG 6.05, Step 6.1, specifies the minimum items to be included on *.he KSREL. However, it leaves off four items from the GL, namely bmteries, battery chargers, inverters, and cooling water pumps. The inspector requested the licensee to review the actual KSRELs for each of the three units to determine if these four items were contained on the lists. The licensee is in the process of reviewing the KSRELs to determine if they meet the minimum specifications of the GL. Unit 3 KSREL is being addressed first; af ter that Units 2 and 1 will be addressed.
- For the 1996 cycle of vendor contacts, PEG determined that there were 39 vendors for equipment on the three units' KSRELs. At the completion of the 1996 cycle, PEG noted that, despite repeated attempts, seven of the 39 vendors failed to respond to requests for information. PEG notified the individual units of tnis and requested an evaluation. There did not appear to be any response to PEG and the inspector could not identify any formal evaluation. Unit 3, Technical Support Engineering, stated that they had reviewed the memorandum and considered that the efforts to produce the new
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107 procedure DC 16 should address it in the future. The <gartment of Programs and Engineering Standards (PES) has begun to address the seven vendors that did not respond via efforts with the new subcontractor PRC/ USA.
- In preparing to send out the vendor requests in 1997, PEG contacted each of the units and asked for review of the KSRELs Some specific questions were noted. Also,in late 1996, Unit 3 sent PEG an updated and expanded KSREL.
The review request letter for Unit 3 had specific questions about this updated list. Again, none of the three units responded to this request and the questionnaires to the vendors were sent out without the needed input from the
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units' engineering staffs. As a result, not all of the vendors on the updated list for Unit 3 were queried. PES, together with Unit 3, is currently developing the actual KSREL for Unit 3. This should be approved soon. At that time, any additional needed ven, Tr contacts and manual updates will be handled through ,
the new contract with PRC/ USA.
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a The licensee has performed a validation of a sample of vendor manuals (38 manuals were validated) for Unit 3 in 1996 and 97. However, not all of the manuals for equipment on the Unit 3 KSREL (or for equipment types listed in
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the GL as key safety-related equipment) were validated, in a July 11,1997, letter to the NRC and a September 5.1997 PES memorandum, the licensee has outlined their plans for vendor manual updates, if the licensee wishes to implement an interim program of lesser scope then they most formally change their original commitments described in their GL response.
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+ As noted above, the licensee has issued a new procedure, DC 16, Vendor
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Equipment TechnicalInformation Program. This procedure addresses receipt
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and control of vendor information and vendor manuals. However, at the time of the inspection the licensee had just begun to implement the procedure, so that review of related activities could not yet be performed. Further, the licensee noted that a revisic~ was necessary due to planned changes in responsibilities in the program. This revision is in progress.
3, Internalhandlina of onsite vendor services As part of the front end of the process for obtaining onsite vendor services, the Procurement Engineering Group (PEG) invokes appropriate requirements on vendors, such as technical and quality assurance requirements,in accordance with procedure NGP 6.02,
- They check the status of any proposed vendor on the approved vendors list. PEG also includes appmerlate requirements into the vendors' contracts such as the Millstone Quality Assurance Program . Additionally, work management procedures (e.g., U3 WC 1, Rev.1, step 1.2.1) require the following checks for work orders generated using vendors:
vendor's responsibility for work and quality cor$ trol are defined in procurement documents, and vendor procedures are reviewed and approved per DC 1.
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108 4. Other INPO 84-010 activities
- These activities include:' participation in SEE-IN and the Nuclear Network, intemal handling of equipment technicalinformation (ETI), and participation in NPRDS. The licensee actively participates in the INPO SEE-IN and Nuclear Network programs. Nuclear Safety Engineering (NSE) is the primary contact for these activities. As part of this activity NSEG receives, ,
evaluates and processes for action INPO operating experience documents, such as SERs, SOERs, and O & MRs. The inspector selected a sample of such dc,cuments, and verified that NSEG had appropriately addressed them. Via the Nuclear Network, the licensee also accesses INPO's World Wide Web Pages for additional operating experience on an expedited basis. The licensee has implemented the recommended enhancement to the SEE-IN program, whereby they report internally identified faults in ETI to the Nuclear Network. The inspector reviewed a number of such reports made by the licensee to the Nuclear Network.
Regarding intemal handling of ETl, the licensee has established administrative controls for
- the review, evaluation, and distribution of this information in DC 16 and PEG 6.05.
Additionally, DC 2, DC 3, dealing with procedure preparation and validation, and DC 16 specify that appropriate ETI should be incorporated into the performance sections of procedures and that the maintenance and operations procedures should cite ETI in the references section of the procedures. These requirements are contained in DC 2, Step 1.1.2, Attachment 2, and Attachment 9; and in DC 3, Attachment 6. The inspector reviewed a sample of procedures and noted that such information was incorporated into the procedures.
Regarding a particular case of ETl previously identified as needing incorporation, the inspector noted that all information for the Unit 3 reactor trip breakers still had not been appropriately incorporated into the procedures. This appeared in three places curing the reviews conducted: deficiencies noted during the vertical slice review, conducted in June, 1996 and repeated in Attachment 2, item C of memorandum PES97-140; NSAL-94-024, Rev.1 issued on March 8,1996 and reviewed by NSEG on May 7,1996; and item 3 of QA Audit Report A24064/A25124 on November 13,1996. The licensee stated that all information would be properly incorporated before startup.
Regarding NPRDS, the licensee had been participating and has procedure RP 4 to cover this activity, in January of 1997, INPO began the transition from NPRDS to a new system called Equipment Performance and Information Exchange (EPIX), and swppeo accepting input into NPRDS. The inspector discussed this transition with the Office of NRR, who is working with INPO to stay informed of the activities. The NRR contact stated that the
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licensee should maintain 1997 information onsite for batching into EPIX when it is operational. They also stated that commitments made to participate in NPRDS should roll over to EPIX. The licensee stated that position is consistent with their current intent and plans. The licensee still has access to the 1996 and earlier data in NPRDS, and that it is still being used as an information source when needed by the licensee.
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109 c. Conclusions As an overview of the VETIP program, the inspector noted that all activities associated with meeting commitments of GL 90-03 should be in place and fully implemented prior to startup. The majority of tht.ae items were verified to be in place during this inspection.
However, the July, 11,1997, NU !etter, B16629, defers some of these commitments to January,1999. The NRC does not concur in the deferrals as described in that letter because it does not meet the intent of the genric letter nor the previous commitment; and notes that, since the letter, additionalitems have been undertaken to be completed before startup.
E1.2 Generic Letter 89-10 Motor Ocerated Valve Proaram Review (Tl 2515/109)
Backaroyad The last NRC inspection of MOV program activities at Millstone was documented in Inspection Report (IR) 96-05 for all three Units. Northeast Utilities (NU) letters titled
" Generic Letter (GL) 8910 Design-Basis C:osure," and dated November 9,1995, and Octob sr 6,1996, for Units 2&3, respectively, indicated that the programs were complete.
Howevor, the programs could not be closed since setups for specific low margin MOVs used valve factors based solely on Kalsi Engineering's KEl Gate software without sufficient justification. In 1997, NU decided not to validate the use of KEl Gate and chose to use the Electric Power Research Institute (EPRI) Performance Prediction Model (PPM) wherever possible consistent with the NRC's safety evaluation report. This technical decision, along with reconstitution of plant system design bases and other administrative reasons, caused major MOV program changes at Units 2&3, including: (1) a new MOV program manual; (2)
the need to revise all design calculations regarding MOV sizing and switch settings; and (3)
MOV design changes including actuator modifications.
E 1.2.1 Summarv Status of Generic Letter 89-10 Motor-Ocerated Valves a. Insoection Scoce (37551)
The inspectors reviewed the "MOV Program Manual," Revision 9, dated August 2,1997, for Millstone Units 2 & 3 and documents associated with valves in the GL 89-10 program.
Using these documents, a valve sample was selected that included examples of methods used by the licensee to demonstrate design-basis capability, b. Observations and Findinas The significant changes to the MOV program included a complete revision of the methods used to establish design-basis requirements. NU's new methods rely primarily on thrust predictions obtained from EPRI's PPM, where these results are to be applied to all valves, both testable and non-testable, under dynamic conditions. Alternate approaches are under development when use of the PPM is not applicable, including dynamic testing, where practicable. The number of MOVs included in the Units 2&3 MOV program remained at 52 and 143 for Units 2 and 3, respectively.
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' To better understand the new methods for establishing thrust requirements, NU prepared for the inspectors documentation packages for the following MOVs:
- 2-CS 16.1 A Containment Sump Outlet isolation Valve
- * 2 RC-403 RCS Block Valve for Power Operated Power Operated Relief Valve
> * 2 SI 616 High Pressure Safety injection Header
Isolation Valve
- 3CHS-MV8105 Charging Flow Control Valve isolation
- 3FWA MOV35B Steam Generator Auxiliary Feedwater isolation
- 3RHS-MV8701C Residual Heat Removal (RHR) Inlet Isolation Valve
- 3SIL-MV8809A RHR Pump Discharge to Cold Leg Containment Penetration
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Each package consisted of thrust calculat;ons, an EPRI PPM methodology for the valve, and a weak link analysis. Allinformation provided was stamped " preliminary". In some cases, the PPM or weak link informat'an was not yet available. Although the inspectors could not make specific findings regarding the design basis capability of these valves, it was clear thet significant changes to the previous MOV thrust requirements were being made, c. Conclusions Significant changas are being made in the methods used by NU to establish design- basis thrust requirements for the 52 MOVs at Millstone Unit 2 and the 143 MOVs at Millstone
- Unit 3.
E1.2.2 MOV Sizina and Switch Settinas a. insoection Scoce (375!ill Most of the licensee's design-basis reviews and thrust calculations were not complete.
NU's methods for determining minimum thrust requirements were documented in Procedure PI 9, " Determination of Stem Thrust Requirements," Revision 4, dated August 2,1997.
The inspectors reviewed draft calculations at Millstone Units 2&3 which included system design-bases and valve thrust requirements. Calculations performed with EPRI's PPM also
were reviewed.
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.b_ Observations and Findincg 1. Valve factors EPRI has tested a sample of valves of various manufacture, type and size to validate a bounding methodology for predicting thrust requirements for a wide variety of valves. The
- NRC identified issues regarding certain specific EPRI tests during its review of the
_
- methodology. Theta issues were resolved with respect to the bounding nature of the EPho meth'odology in developing an NRC safety evaluation.
Until recently, valve factor results for non-dynamically tested valves were obtained from '
Kalsi Engineering's KEl Gate software to establish thrust requirements. While the KEl Gate software was reported by NU to provide results equivalent to the PPM, KEl Gate results were in the form of valve factors, as compared to a total thrust requirement provided by the PPM. Since the KEl Gate methodology did not receive detailed NRC review similar to
- the EPRI PPM, the NRC concluded in IR 96-05 that NU would need to acquire additional Lindustry information to validate KEl Gate results.
To resolve this issue, NU discontinued the use of KEl Gate and intends to fully implement '
results obtained from the PPM, including the conditions and provisions contained in the NRC safety evaluation (SE) of EPRI's PPM, dated March 15,1996. NU will use the PPM for all MOVs where it is applicable which includes some MOVs that otherwise could be tested under dynamic conditions. For valves to which the PPM is not applicable, the licensee is developing alternative approaches, such as the use of dynamic testing. All alternate approaches (about 11 MOVs at Unit 2 and 34 MOVs at Unit 3) will be incorporated into Procedure PI-9 of the MOV Program Manual,
,
2. Load Sensitive Behavior A margin of 10% was originally assumed to account for the effects of load sensitive behavior. Rcr9ntly, this assumption was revised to include a bias margin of 5.6%, and a random margin of 26.4% which is combined with other random errors using the square-root sum of the squares methodology. The new assumption is based on results published by EPRI as part of the Performance Prediction Program (PPP). These assumptions are not
"
yet supported by in-plant test results.
3. Stem Friction Coefficient
- The MOV progra- origina: y used a stem friction coefficient assumption of 0.15. Recently, this assumptic ; vas increased to 0.20 based on a stem lubrication frequency of every refueling cycle, which is designed to maintain a well lubricated stem-to-stem nut interface, reviews of industry data, and a limited review of Millstone-specific test are planned dats.
Additional dynamic tests are planned prior to program closure to confirm that dynamic test data support the 0.20 stem friction coefficient assumption.
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112 4. Degradation Marain The NRC previously found that the lice 1see had not identified a specific margin to account for valve degradation. Licensee personnel stated that the limited stem friction coefficient data available nonetheless indicated that stem lubricant degradation was not a concern.
After further review, a 10% margin was incluoed for thrust degradation in the thrust calculations. While this assumption is not yet supported by in-plant data, information will be acquired during the long term periodic verification MOV program. The inspectors considered this approach to be acoptable.
c. Conclusions Additional test data for site-specific load sensitive behavior and stem friction coefficient are necessary to coniirm the cu~ent program assumptions.
E1.2.3 MOV Desian-Basis Caoabilitv a. Insoection Scooe (37551)
The inspectors reviewed thrust calculations and actuator capability assessments for the selected MOVs with specific focus on the power operated relief valve (PORV) block valves.
The purpose of this review was to assess NU's efforts to establish design-basis capability for all MOVs in the GL 8910 program, b. Observations and Findinas The Unit 3 PORV block valves (3RCS-MV8000A & B) are being replaced with new,3" diameter, Anchor / Darling,1500# double-disc gate valves that were modified to improve structural weak-link considerations. To ensure proper valve design and actuator sizing, NU specified that a prototype of these valves be tested under design-basis steam blowdown conditions. Initial testing was conducted recently at Duke Power's Marshall test facility which resulted in valve seat damage that was later resolved by modifying the valve's internal clearances. The modified prototype valve subsequently was tested successfully.
The inspectors noted that no testing was planned for the actual production valves. NU personnel stated that the PPM will be used to establish the valves' thrust requirements and the prototype test results will be used only to support the PPM results. However, due to the modified nature of the prototype test valve, the PPM is no longer directly applicable.
Further, manuf acturing tolerances will affect the direct applicability of the prototype test.
Therefore, additional justification is necessary to establish the long-term thrust requirements for these valves. (IFl 50-423/97-203-15)
During review of the design-basis differential pressure requirements for Unit 2 PORV block valve 2-RC-403, the inspectors noted that 2250 psid was identified as the worst case differential pressure for the close direction. The licensee's analysis stated that 2-RC-403 would need to close in case the associated PORV were to stick open during recovery from a reactor coolant system (RCS) over pressurization event. However,2250 psi is normal RCS operating pressure. The technical basis for selectiag normal operating pressure for
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113 recovery from an over pressurization event was not clear. The inspectors requested NU to provide additional justification for this assumption. This item will be reviewed further during a future MOV program closure inspection. (IFl 50 336/97 203 16)
Program Instruction PI-13, " Evaluation of Dynamic Test Results," contained criteria to be used to evaluate MOV dynamic test results. Test evaluations performed prior to returning an MOV to service were contained in Attachment A, " Operability Review Data Sheets."
The inspectors noted that the " Test Differential Pressure Evaluation With Valve Closed" sheet (Page A-4) contained an inccrrect variable reference used in the equation used to calculate the test differential pressure conditions. NU ;;ersonnel acknowledged that the equation was incorrect and intend to initiate a revis!on to PI 13.
NU linearly 3xtrapolated dynamic test results to account for differences between test conditions and design basis conditions. NU justified the use of linear extrapolations based on results from EPRl's PPP However, the inspectors noted that the licensee's extrapolation methods did not include EPRI's latest recommendations for identifying the disk loads that are necessary to ensure that test results are reliable. Licensee personnel agreed to include this guidance in Millstone's MOV Program Manual, c. Conclusions The inspectors found that additional justification will be needed to support the design-basis differential pressure and long-term thrust requirements of the Units 2&3 PORV block valves.
E1.2.4 Pressure Lockina and Thermal Bindina a. Insoection Scoce (37551)
The inspectors reviewed the licensee's submittals, dated October 6,1995, February 13, August 7 and 22,1996, and June 23,1997, regarding Generic Letter (GL) 95-07,
" Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves" as applied to Millstone Units 2&3.
b. Observations and Findinas Unit 2 The licensee provided a calculation which was used to demonstrate that the containment spray system containment sump suction valves (2-CS-16.1 A and B) would operate during a pressure locking condition. Calculation assumptions were that (1) air was in the valve bonnets, (2) some leakage from the bonnets would occur, and (3) the standard industry double disk formula accurately predicted the thrust to overcome pressure locking. In another calculation regarding a potential pressure locking condition for pressurizer power-operated relief /alve (PORV) block valves (2-RC-403 and 405), the inspectors noted that the licensee used a pressure locking methodology that was not validated. The licensee was unable to validate the above assumptions used to demonstrate that valves 2-CS-
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- 16.1 A and B and 2 RC 403 and 405 would operate during pressure locking conditions.
They agreed to resolve the inspector concerns by providing a supplemental response to GL-95-07, j in its August 7 submittal, the licensee stated that the turbine driven auxillery feed water 1 pump steam admission valves (2 MS 201 and 202) were susceptible to thermal binding and the valves would be cycled periodically to address this condition. The inspectors reviewed .
procedure OP-2322, Auxiliary Feedwater System, Revision 23, and noted that the procedure did not include instructions to periodically cycle these valves. The licensee was unaware of this error in Procedure OP 2322. Apparently the correct instructions had been included in Change 8 of Revision 22 on July 23,1995, but were inadvertently deleted
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during a subsequent revision on December 15,1995. This procedure inadequacy is a
- violation of 10 CFR 50, Appendix B, Criterion V, Procedures. (VIO 50 336/97 20317) The-licensee issued Condition Report M2 971573 on August 6,1997, to correct Procedure OP- ,
2322 and agreed to indicate this corrective action in a supplemental response to GL 97-05.
The inspectors verified that appropriate instructions had been included in other procedures
- to address potential thermal binding concerns for valves 2 RC-403 and 405 and 2 SI 651
- and 652. Also, valves 2 SI-651 and 652 had been modified to prevent pressure locking.
Unit 3 i
d The licensee stated in the October 6 submittal that the steam generator PORV block valves (3 MSS *MOV18A,B,C, and D) were susceptible to thermal binding. As corrective action, the licensee submitted a Technical Specifications change to require that, when the valves are shut, they should be declared inoperable and the appropriate Technical Specifications action statement entered. The Technicai Specification change was submitted to the NRC for approval in the licensee's Letter B 16550, dated July 18,1997, which would be i implemented prior to Unit 3 restart.
The licensee issued Design Change M3 97-007 to modify the pressurizer PORV block
valves (3RCS*MV 8000A and B). The inspectors reviewed this modification and verified that these valves were scheduled to be replaced during the current outage with modified
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double disk valves that are not susceptible to pressure locking or thermal binding. The inspectors reviewed Procedure OP 3201, Plant Heatup, Revision 13, and verified that the residual heat removal cooldown suction isolation valves,3RCS*MV8701 A,B,C and
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_3RCS*MV8702 A,B,C are shut when RCS temperature is approximately 200 F, and, therefore, not susceptible to thermal binding. - The inspectors reviewed drawings -
2282.050-6761121 and 2882.050 6761031 and verified that valves 3RCS*8701 A,B,C and 3RCS*8702 A,B,C and 3SIL*MV8804A,B and 3RSS*MV8837A,B, and 3RSS*MV8838 A,B were modified to prevent pressure locking. ;
< l
. c. Conclusions The adequacy of the licensee's actions to address the pressure locking and thermal binding '
concerns at Units 2&3 remain under NRC evaluation. The inspectors identified an error in j-Unit 2 Procedure OP_2322 regarding the omission of instructions to periodically cycle 2- _
MS 201 and 202 to address thermal binding. The licensee agreed L. provide a
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supplemental response to GL 97-05 to address the assumptions used in pressure locking
. calculations for Unit 2 valves 2-CS 16.1 A and B, 2-RC-403 and 405, and to describe the corrective action implemented for Unit 2 valves 2-MS-201 and 202, These items will be reviewed by the NRC in preparing a safety evaluation of the licensee's responses to GL 97-05.
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E1.2.5 MOV Program Oroanization a. Insoection Scoce (37551)
{ The inspectors reviewed the revised MOV program organization recently established for the three Millstone units. This review also included the scope of MOV overhaul and modification work planned to support unit restart, b. Observations and Findings
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A new MOV organization has been in place since April 1997 to serve all three Millstone
units. The staffing consisted of a knowledgeable MOV Program Manager (temporarily on-
! loan from another utility) and other lead and support MOV personnel with a total complement of 90-100 people. These changes evidenced a commitment of resources by NU management to correct MOV program problems and to fully implement the
! commitments regarding GL 8910. The current MOV organization has six permanent NU personnel, and a search was underway for a permanent MOV Program Manager.
Substantial work remains to be done including MOV n.odifications of about 30 actuators at
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Unit 3 and 5 actuators at Unit 2, the overhaul of all MOVs which includes static testing, and some dynamic testing at both units. ,
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c. Conclusions i Substantial resources in fonWg a new MOV organization had been allocated to correct
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MOV program problems. However, the organizational changes have not been in place long 4- enough to assess their effectiveness regarding MOV activities. Also, many MOV modifications, overhauls, and testing remain to be done.
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E8 Miscellaneous Engineering issues (Update - Unit 2 Significant items List No.
20)
E8.1 (Closed) IFl 50-245.-336 & 423/95-01-01 Item 1: Incorocration of Rate of Loadino Margin IR 95-01 noted that NU had selected a 10% thrust margin to bo included into the Unit 2 thrust calculations to account for the effects of load sensitive behavior (also known as rate of loading). However, the inspectors also noted that the thrust calculations that existed at
'
that time did not yet include this margin. Subsequent to that inspection, NU revised the
- load sensitive behavior assumptions to reflect the following
- a 5.6% bias margin and a 26.4% random margin to be included with other random errors using the square-root sum
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of the squares methodology. The licensee presented example calculations that incorporated the new margins. While NU has not completed revisions to all Unit 2 calculations, the licensee has committed to have these margins fully incorporated prior to unit restart. NU's actions and commitments are considered adequate to close out inspector Followup item 95-01-01, item 1.
E8.2 (Undate) IFl 50-245. 336. & 423/95-01-01 Item 2 and IFl 50-423/95 17-03:
Rate of Loadino & Stem Friction Coefficient Justifications
IR 95 01 documented that the licensee had not completed the program justifications for load sensitive behavior (also known as rate of loading) and stem friction coefficient.
Subsequent to this inspection, NU revised its load sensitive behavior (5.6% bias /26.4%
random) and stem friction coefficient (0.20) assumptions. NU based these new selections on a review of results obtained from EPRl's Performance Prediction Program (PPP) and on
, the requirement to perform stem lubrication every refueling cycle. The inspectors noted i that the new program assumptions will need to be supported by analysis of in-plant data and cannot be completed until Millstone's dynamic test program is finished. Completion of these justifications will be reviewed during a future MOV program closure inspection.
Therefore, this issue will remain open.
E8.3 (Closed) IFl 50-245. 336. & 423/95-01-01 Item 3: Actuator Insoections When
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Extended Ratinas Are Acolied
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IR 95-01 noted that NU was using a study performed by Kalsi Engineering to extend the
, thrust ratings 'or selected actuators up to a maximum of 162% of the published ratings.
No specialinternal actuator inspections were planned for these MOVs to ensure that the extended ratings do not create unexpected internal structural concerns. In response to this -
concern, NU added requirements to Procedure PI 10, *MOV Periodic Testing, Periodic
,
Verification and Tracking" to inspect the thrust bearing components. This was considered to be acceptable, and Inspector Followup item 95-0101, item 3 is closed.
"
E8.4 (Closed) IFl 50-245. 336. & 423/95-01-01 Item 4: Linear Extracolation IR 95-01 noted that NU had reduced the minimum allowable cutoff for application of linear extrapolations from 80% to 50%. Prior to this revision, NU used engineering judgement to evaluate dynamic tests that were performed at differential pressures that were less than 80%. This program change resulted in some dynamic tests that required reevaluation. NU has since revised the emphasis of the MOV program to maximize the use of EPRI's PPM to
'
justify design basis thrust requirements. However, some axisting dynamic test results may still need to be credited for GL 8910 program closure.- Any test results that are used will be reviewed using the criteria contained in Procedure PI-13, " Evaluation of Dynamic Test Results." The Pi ensures that all dynamic test results are extrapolated in a justified i manner. Therefore, the inspectors considered Inspector Followup item 95-0101, item 4 issue closed.
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117 E8,5 - (Closer!) IFl 50-245. 336. & 423/95-01-01 item 5 and IFl 50-423/95-17-05:
Dearadation Marain
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IR 95-01 (Unit 2) and IR 95-17 (Unit 3) noted that the MOV program did not include any margin for valve degradation when evaluating dynamic test results. To resolve this issue.
NU added requirements to the data evaluation sheets contained in Procedure P! 13 to ensure that a 10% margin is reserved for MOV degradation. Based on this action, the ,
inspectors consider IFl 50-245, 336, & 423/95-0101, item 5 and IFl 50-425/95 17-05 closed,
- E8.6 (Uodate) IFl 50-245. 336. & 423/95-01-01 Item 6 Justifv All Non-Dynamically Tested MOV Valve Factors
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- IR 95-01 documented that NU was applying a generic O.90 valve factor to the thrust calculations of some non-dynamically tested MOV to show that the valves had a large available thrust margin, and to justify that no further effort was needed to establish an
- appropriate valve factor for these valves, NU is now using EPRl's PPM as the primary method to establish MOV thrust requirements. However, the PPM will not be applicable to
,
all MOVs at Millstone. Therefore, alternate approaches will need to be developed to justify -
the thrust requirements for certain MOVs.
E8,7 (Closed) IFl 50-423/95-17-01: Use of KEl Gate IR 9517 (Unit 3) documented NU's intent to use valve factor results from Kalsi Engineering's KEl Gate sof tware to justify thrust requirements for non-dynamically tested MOVs at Millstone, The inspectors were concerned with this approach because the KEl Gate methodology did not receive the same NRC review as EPRl's PPM. To resolve this issue, NU has de,cided to use PPM results for applicable MOVs at Millstone. This will
establish thrust requirements using an approach that has been reviewed and approved by
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the NRC. Therefore, the inspectors considered inspector Followup item 50-423/95-17 01 closed.
E8.8 (Closed) IFl 50-423/95 17-02- Acolication of Measurement Uncertaintv
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IR 9517 noted that the licensee was applying valve factors that were based on as-read thrust values from the diagnostic traces. The inspectors were concerned that the uncertainty associated with the calculated valve factor was not accounted for. To resolve--
this issue, NU revised Procedure Pl.13, Attachment B, " Dynamic Test Evaluation Data Sheets" to account for diagnostic equipment uncertainties when calculating valve factors.
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After review of Attachment B, the inspectors considered this issue closed.
E8.9 (Closed) IFl 50-423/95-17-04: Evaluatiorwf Load Sensitive Behavior I
IR 9517 noted that, early in Millstone's MOV program, dynamic test evaluation procedures
.. did not account for load sensitive behavior if the measured value was less than 5%. NU
later revised this assumption, but had not reevaluated any of the dynamic tests that were conducted prior to this program change. NU's existing approach is to use the PPM to
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118 establish MOV thrust requirements where possible. However, some dynamic testing will still be relied upon for justifying specific thrust requirements. NU personnel stated that the current data review process accounts for any measured load sensitive behavior. Further, if g any of the older dynamic tests are used, these tests will be reviewed using the current requirements. Based on this information, the inspectors consider inspector Followup item 50-423/95-17 02 closed.
VI. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusico of the inspection on October 1,1997. The licensee acknowledged the findings presented.
X 1.2 Final Safety Analvsis Reoort Review
A recent discovery of a licensee operating their facility in a manner contrary to the updated final safety analysis report (UFSAR) description highlighted the need for additional verification that licensees were complying with UFSAR commitments. All reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures and parameters.
While performing the inspections which are discussed in this report the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters.
X 1.3 Sionificant items List issues This inspection report characterizes Unit 2 Significant items List (SIL) Nos. 22,29, and 35 ,
as " closed" based on the NRC's determination that the technical concerns associated with these SIL items have been adequately addressed by the licensee. However, the escalated enforcement items (Eels) referenced in the SIL item remain open pending NRC considerations of potential escalated enforcement action. NRC Inspection Report (IR) 50-336/97-02 and IR 50 336/97 202 discuss SIL Nos. 26,33,34, and 36 in which, similarly, the techrical issues were adequately addressed and there is pending escalated enforcement actions, however, these reports characterized these Sllitems as " updated" rather than
" closed". To avoid confusion with other _" updated" (incomplete) SIL items, the NRC is now characterizing SIL Nos. 2". W, J4, anbd 36 as " closed" to make it clear that no additional NRC inspection of these items is considered necessary prior to restart (alhough the NRC reserves the opetion of performing additionalinspection.) The processing of future Units 1, 2 and 3 SIL issues will be done, accordingly.
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119 c INSPECTION PROCEDURES USED -
IP 37551 Onsite Engineering IP 40500 Licensee Self Assessments Related to Safety issues inspections
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IP42001 Emergeray Operating Procedures
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IP 62700 Maintenance Program implementation i
IP 62707 Maintenance Observations IP 71707 - - Plant Operations t
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IP 83750 -Occupational Radiation Exposure .;
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- IP 86750 Solid Radioactive Waste Management and Transportation of Radioactive Materials IP 92700 - Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
- Facilities IP 92901 Followup Operations
IP 92902 Followup Maintenance IP 92903 Followup Engineering i IP 92904 Followup Plant Support
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120 ITEMS OPENED, CLOSED, AND DISCUSSED Ooened URI 50 245/97-203-01 U101.2 Assessment of Condition Report Evolutions VIO 50-245/97 203-02 U1 M1.1 Gas Turbine Generator Maintenance URI 50 245/97 203-03 U1 E1.2 Temporary Shielding Program URI 50 336/97 203-04' U2 03.1 No AOP for Loss Containment Integrity URI 50-336/97 203-05 U2 E8.1 Adequacy of Corrective Actions Taken in Response to IEB 79-02 and 7914 URI 50 336/97 203-06 U2 M2.1 Rosemount transmitters eel 50-423/97-203 07 U3 M8.1 Inadequate ECCS flow path
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IFl 50 423/97 203-08 U3 M8.1 Implementation at ECCS flow modifications URI S0 245:336:423/97 203-09 U3 E.8.5.1 EQ Documents Need to Reflect New Program URI 50-423/97 20310 U3 E8.5.3 PASS SOV not functional post LOCA -
URI 50-423/97 20311 U3 E8.7 Appendix R Equipment Testing URI 50-423/97 20312 U3 E8.10 Inservice Testing of Pumps VIO 50 245;336:423/97-203-13 IV R1.1 Failure to Follow Written HP Procedures VIO 50 245;336:423/97 20314 IV R1.2 Rad Levels for a Limited Quantity Shipment in Excess of the Limit IFl 50-423/97 20315 V E1.2.3 MOV Long Term Thrust Requirements IFl 50 336/97-20316 V E1.2.3 PORV Block MOV Calc Assumes NOP vs. Overpressure
.VIO 50-336/97 20317 V E1.2.4 Procedure to Prevent The: mal Binding of TDAFW Steam Admission Valves Closed VIO 50-245/95-044 03 & 04 U 1 08.1 IFl 50-245/96-13 01 IV R8.2 IFl 50 245/96-13-02 IV R8.3 VIO 50-245/96-09 20 S8.2 IFl 50 336/95-201-06 U2 08.1 -
VIO 50-336/97-0213 U2 08.2 URI 50 336/96 0610 U2 E8.2
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VIO 50 336/9613-01 IV R8.5-(IFS ITEM 96-13-04) IV R8.5 URI 50-423/96-04-13 U3 E8.6.1 URI 50 423/96-0414 U3 E8.6.2 URI 50-423/96-04-15 U3 E8.6.3 URI 50-423/96 06-14 U3 M8.1
- URI 50-423/96-201-16 U3 E8.11 IFl 50-423/97-202-05 U3 E8.10 IFl 50-423/9517-01 V.E8.7
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121 IFl 50 423/9517-02 V.E8.8 IFl 50-423/9517 04
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V.E8.9 VIO 50-245;336;423/96-09-04 U3 08.1
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- VIO 50-245;336:423/96-0918 VI R8.1 eel 50-245;336;423/96-0515 VI S8.1 eel 50-245;336:423/97 03-03 VI S8.1 IFl 50 245;336:423/95-01-01 Item 1 - V.E8.1 IFl 50 245:336:423/95-01-01 Item 3 V.E8.3 IFl 50 245:336:423/95 01-01 Item 4 V.E8.4 IFl 50-245 336:423/95-01-01 Item 5 V.E8.5
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eel 50 245:336:423/97-03-01 VI S8.3 Discussed
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- VIO 50-245/96-13 01
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(IFS ITEM 96-13-04) VI R8.4 -
IFl 50-336/96-13-01 VI R8.5 (IFS ITEM 96-13-05) VI R8.6 eel 50-336/98-08-08 U2 f 481 URI 50 336/96-06-08 U2 E8.1 eel 50-336/96-06-11 U2 E8.2 eel 50-336/96-06-12 U2 E8.3 eel 50-336/96 201 11 U2 E8.4 eel 50-336/96 201-31 U2 E8.4 eel 50-336/96 201-12 U2 E8.5 eel 50-336/96-201-28 U2 E8.6 eel 50-423/96-06-15 U3 E8.4 eel 50 423/96-201-02 U3 E2.4 EEi 50-423/96-201-07 U3 E8.9 eel 50-423/96-201 13 U3 E2.2 eel 50-423/96-201 18 U3 M2.2 eel 50-423/96-201-19 U3 M2.1
- eel 50-423/96 201-22 U3 08.3 eel 50 423/96-20127 U3 E8.8 eel 50-423/96-201-37 U3 E2.1 eel 50 423/96-20139 U3 E8.2 IFl 50-245:336;423/95 0101 Item 2 V. E8.2 eel 50 245:336:423/97-03 02 VI S8.4
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IFl 50-245:336;423/95-0101 Item 6 V. E8.6 50-423/95-17-05- U3 E8.5 i
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122 lhe followina LERs were also closed durina this insoection:
50-423 96-02 96 03 96 07 Sup1&2 90 15 03
- 96-29 96 38 96-48 96-49 96-51 97-07 97-18 97 25 97 26
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123 uST oF ACRONYMS USED
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-AACL alternate AC-ACR(s) advme condition report (s)
ACU(s) air conditioning unit (s) ~
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-ALARA as low as reasonably achievable AOP(s) abnormal operating procedure (s)
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ARP(s)- alarm / annunciator response procedure (s)
AWO(s) ' automated work order (s)- '
BTP branch technical position CAS central alarm station
~ CCP reactor plant component cooling ;
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CCPL_ chemical consumable product list
-. CFR - Code of Federal Regulations
'CHS charging system CMP configuration management plan CR(s) condition report (s)
CRAC control room air conditioning DBA design basis accident DBD design basis document
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DBDP(s) design basis documentation package (s)
design basis summary
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DBS DCN(s) design change notice (s)
DCR design change record DDR(s) design deficiency report (s)
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DNBR _- departure from nucleate boiling ratio
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DRS Division of Reactor Safety DWST deminerall:ed water storage tank EA escalated enforcement ,
, EDG(s) . emergency diesel generator (s)
eel (s) - escalated enforcement item (s)
EEQ electrical equipment qualification EMI electromagnetic interference EOP(s) ~ emergency operation procedure (s)
- EPlX equipment performance and information exchange
EPRI Electric Power Research Institute
- EOML equipment qualification master list EQR(s). equipment qualification record (s)- :
ERT event review team i ESAS engineered safeguards actuation system ESF ' engineered safety feature ETI equipment technical information .
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'FLB. feedwater line break :
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- FSAR_ Final' Safety Analysis Report --
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_FTE . full time equivalent l FTSP. = fire transfer switch panel l GL. Generic Letter
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I 124 HELB high energy line break HPSI high pressure safety injection HPU hydraulic power unit ICAVP Independent Corrective Action Verification Program IDS intrusion detection system IFl inspector follow item INPO Institute of Nuclear Power Operators ISEG independent safety engineering group ISI inservice inspection KSREL key safety-related equipment list LCO limiting condition for operation LCR loop calibration report LDST letdown storage tank LER(s) licensee event report (s)
LOCA loss of coolant accident LPCI low pressure coolant injection LPSI low pressure safety injection MCC motor control center MCR main control room MEPL(s) material, equipment, and parts list (s)
MOV(s) motor-operated valve (s)
MRPM Millstone reevaluation project memo MRT management review team MSTCL master surveillance test control list NCR(s) nonconformance report (s)
NGP(s) nuclear guidance procedure (s)
Ni nuclear instrumentation NIST NationalInstitute of Standards and Technology NNECO Northeast Nuclear Energy Company NRB nuclear review board NRC Nuclear Regulatory Commission NRR Nuclear Reactor Regulation -
NSAB nuclear safety assessment board NSIC Nuclear Safety information Center NSEG Nuclear Safety Energy Group NSR nonsafety related OCA Office of Congressional Affairs OEDO Office of Executive Director for Operations OP(s) operating procedure (s)
PAO Public Affairs Office PAOTE post-accident operating time extrapolation PDCR plant design change record PDR Public Document Room PMMS production maintenance management system PORC plant operation review committee PORV(s) power operated relief valve (s)
PPM performance prediction model PPP performance prediction program PRND power range neutron detectors
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h 125 UA quality assurance CSS quench spray system RATI restart assessment team inspection RBCCW reactor building closed cooling water RCP(s) reactor coolant pump (s)
RCS reactor coolant system RECO reasonable exrectation of continued operability RG Regulatory Guide RSS recirculation spray system RSST reserve station service transformer R W P(s) radiation work permit (s)
RWST refueling water storage tank SAPG stat i on administrative procedure group SBO station blackout SCEW system component evaluation worksheet SER(s) safety evaluation report (s)
SFM(s) safety function requirement (s)
SFM(s) security force member (s)
SFP spent fuel pool SlH high pressure safety injection Sll significant item list SLB steam line break SLC standby liquid control SOV(s) solenoid-operated valve (s)
. (s) surveillance procedure (s)
SPO Special Projects Office SPROC special procedure SWEC Stone & Webster Engineering Corporation SWP plant service water TCV(s) thermostatic control valves TDAFW turbine driven auxiliary feedwater TDAFWP turbine driven auxiliary feedwater pump TLD(s) thermo-luminescent dosimeter (s)
TMI Three Mile Island TRA(s) test report assessment TRM Technical Requirements Manual TS(s) technical specification (s)
UFSAR updated final safety analysis report UlR(s) unresolved indication report (s)
URl(s) unresolved item (s)
VCT volume control tank VETIP vendor evaluation technical information program VIO violation WC work control
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