IR 05000336/1998213
| ML20155B186 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 10/23/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20155B115 | List: |
| References | |
| 50-336-98-213, NUDOCS 9810300081 | |
| Download: ML20155B186 (24) | |
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i U.S. NUCLEAR REGULATORY COMMISSION
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OFFICE OF NUCLEAR REACTOR REGULATION
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Report No.:
50-336/98 213 I
Docket No.:
50-336
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Licene No.:
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Licen. tee:
Nor'heast Nuclear Energy Company Facili'y:
Millstone Nuclear Power Station, Unit 2 Location:
Millstone Nuclear Power Station 156 Rope Ferry Road Waterford, Connecticut 06385 Dates:
August 10 through September 3,1998 Inspectors:
Richard P. McIntyre, ICAVP, Team Leader ICAVP, ADT, NRR Brian Hughes, Operations inspector, ICAVP, ADT,NRR Paul Narbut, Operations inspector, ICAVP, ADT, NRR James Houghton, Mechanical Engineer, ICAVP, ADT, NRR Robert Quirk, l&C Engineer, Contractor *
Approved by:
John A. Nakoski, ICAVP Program Coordinator Millstone independent Corrective Action Verification Program inspections Associate Director for Technical Review Office of Nucler.r Reactor Regulation l
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9810300001 981023 i
PDR ADOCK 05000336
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0 TABLE OF CONTENTS
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i EXEC UTIVE SUM MARY... '................................................... I I
i 1.0 B a ckg round......................................................... 1 1.1 Scope of N RC Review.............................................. 1 2.0 M ech a n ica l......................................................... 2 2.1 Millstone Site Observations and Findings............................... 2 2.2 Observations and Findings at Parsons................................. 3 2.3 Conclu sions...................................................... 3 3.0 Instrumentation and Controls........................................... 4 3.1 Millstone Site Observations and Findings............................... 4 3.2 Observations and Findings at Parses >............................... 6 3.3 C o n cl u sio n s................... '................................... 6 4.0 Operation s.......................................................... 7 4.1 Millstone Site Observations and Findings............................... 7
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4.2 Observations and Findings at Parsons................................ 10 l
4.3 C o nclu sio n s..................................................... 10
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5.0 Entrance and Exit Meetings............................................ 11 Appendix A List of Apparent Violations, Unresolved items, and incpector Followup Items. A - 1 Appendix B Entrance and Exit Meeting Attendees.............................. B - 1 Appendix C List of Critical Design Characteristics (CDCs)......................... C - 1 Appendix D List of Acronyms............................................... D - 1
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EXECUTIVE SUMMARY From August 10 through September 3,1998, a team from the U.S. Nuclear Regulatory Commission's (NRC's), independent Corrective Action Verification Program (ICAVP) Inspection Oversight staff of the Office of Nuclear Reactor Regulation, in accordance with the guidelines outlined in SECY 97-003," Millstone Restart Review Process," conducted a Tier 2 Accident Mitigation Systems inspection st Millstone Unit 2 and at the offices of Parsons Power Group inc. (Parsons), the Unit 2 ICAVP contractor.
The objectives of the Tier 2 inspection were to (1) independently assess the licensee's ability to
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identify and resolve licensing-basis deficiencies, focusing mainly on the period of the licensee's Configuration Management Plan (CMP) implementation; (2) verify that critical design characteristics (CDCs) of systems relied upon to mitigate the consequences of accidents analyzed in Chapter 14 of the Final Safety Analysis Report (FSAR) were consistent with those used in the design of the mitigation systems; and (3) assess the effectiveness of the Tier 2 l
aspects of Parsons'ICAVP. The Parsons Tier 2 reviews were designed to be narrower in scope than those performed on the Tier i systems selected by the NRC. The Tier 2 reviews began after the selected CDCs were approved by the NRC. Parsons then determined if the selected CDCs could be met by these systems through a review of documents and information such as design requirements, supporting accident analyses and calculations, test procedures and results, surveillance procedures and results, emergency, abnormal, and routine operating procedures, and various corrective action docun:ents. This review provided a measure of confidence that the licensee's accident mitigation systems were adequately designed and tested and would perform as assumed in the accident analyses.
The team thoroughly reviewed certain important aspects of accident mitigation systems. The NRC's Tier 2 team inspection performed a focused functional review of the systems involved in the mitigation of two accident scenarios: the main steam line break (MSLB) analyses for the containment (FSAR Section 14.8.2.1) and the reactor coolant system (RCS) (FSAR Section 14.1.5); and the small-break loss-of-coolant accident (SBLOCA) (FSAR Section 14.2.7). The
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team selected a sample of CDCs related to the mitigation systems for these two accidents and performed a systematic verification that the design basis, construction, operation, training, and testing were consistent with the assumptions made in the accident analyses.
The team reviewed approximately 92 CDCs for the two accidents selected. Based on results of this sample review, the team determined that the input data for the accidents analyzed in Chapter 14 of the FSAR appeared consistent with the performance of the mitigation systems and that the accident analyses should be adequate to maintain the Unit 2 design and licensing bases.
The team found that the Parsons Tier 2 ICAVP review was conducted in accordance with the NRC approved ICAVP Audit Plan and project procedures and that the reviews were conducted in a thorough, detailed and critica! manner. Generally, the findings identified by the team were consistent with the findings identified by the Parsons ICAVP. For example, Parsons identified similar problems with the use of procedures in the "DO NOT USE" status, and the calibration of measuring and test equipment.
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The team identified one violation during the site inspection. The violation involved multiple examples of the failure to translate design basis requirements into plant procedures. This violation is considered equivalent to an ICAVP Significance Level 3 finding. The number of issues identified in this violation appears to be indicative of P configuration control weakness in the translation or reconciliation of the accident analyses inputs and results with station
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procedures and other supporting engineering analyses that form the bases for the system design.
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l The team also concluded that the licensee had identified and resolved many important CMP
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deficiencies and was implementing several improvements to the program by issuing condition reports (CRs) and action requests (ARs) in response to the team's findings. In accordance with NRC policy, when the team identified a problem that the CMP had already identified and that
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had been or was being corrected, the team did not issue a violation. Also, the team observed a number of strengths and good practices. For example, licensee personnel responded well to the team's questions and concems, the Unit 2 design engineering group exhibited sound technical knowledge, and the licensee demonstrated relatively good information retrieval capabilities.
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1.0 Backaround
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On August 14,1996, the U.S. Nuclear Regulatory Commission (NRC) issued a Confirmatory Order (Order) to the Northeast Nuclear Energy Company (NNECO or the licensee) requiring completion of an Independent Corrective Action Verification Program (ICAVP) before the restart of any Millstone unit. The Order directed the licensee to obtain the services of an organization independent of the licensee and each facility's design contractor to conduct a multidisciplinary review of Millstone Units 1,2, and 3. On July 15,1997, the staff approved NNECO's selection l
of the Parsons Power Group Inc. (Parsons) to perform the ICAVP for Millstone Unit 2. This
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inspection focused on the Tier 2 aspects of the ICAVP, in a Commission paper, SECY-97-003, " Millstone Restart Review Process," dated January 3,1997, the staff described the Millstone restart review process. To provide the necessary assurance to support a unit restart decision, the staff's expectation, described in l
SECY-97-003, was that the ICAVP would encompass the aspects of configuration control l
through a three tiered approach.
The objective of the Tier 2 review was to provide assurance that the performance of accident mitigation systems agreed with that input into the accident analyses. To evaluate the capability of accident mitigation systems subject to the Tier 2 review, the contractor selected design characteristics of these systems that were specified in Chapter 14 of the FSAR and submitted them to the staff for approval. The ICAVP contractor evaluated the NRC-approved CDCs by performing a review of documented surveillance tests, plant startup tests, or a critical review of design calculations, specifications, vendor documents, and drawings to assess conformance with the system performance input to the accident analyses.
1.1 Scoce of NRC Review The NRC's Tier 2 inspvction consisted of a thorough review of two postulated accidents analyzed in the FSAR. The team selected a sample of critical functions performed by the mitigation systems and systematically verified that the design basis, construction, operation, training, and testing were consistent with the assumptions made in the accident analysis. The NRC's Tier 2 inspection focused on the main steam line break (MSLB) analyses for the containment (FSAR Section 14.8.2.1), and the reactor coolant system (RCS) (FSAR Section 14.1.5); and the small break loss of coolant accident (SBLOCA) (FSAR Section 14.2.7).
The team selected a sample of CDCs for the accidents scenarios chosen and reviewed mechanical systems, instrumentation and control, and plant operations aspects of the CDCs.
By independently evaluating approximately 92 of the Tier 2 CDCs reviewed by the contractor, the team gained insights in two areas: (1) whether the contractor implemented the ICAVP in a critical and thorough manner; and (2) whether the licensee's CMP adequately corrected the Tier 2 aspects ofits configuration management problems. The team also observed operators in the plant simulator to observe their actic.ns in response to the MSLB and SBLOCA accident scenarios with an emphasis on the times required to perform operator actions assumed in the analyses.
Finally, the team went to Parsons' offices in Reading, PA, ar'd compared its Tier 2 findings from the site inspection and the results of the Parsons review. While at Parsons' offices the team also assured that Parsons had followed its planned evaluation of the CDCs for the selected accident scenarios in an acceptable manner.
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O Appendix C to this report lists the initial or bounding conditions, or the CDCs and associated design parameters reviewed by the NRC inspection team.
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2.0 Mechanical
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i 2.1 Millstone Site Observations and Findinas l
The team found that for the majority of CDCs sampled for the mechanical systems and components discipline had been successfully translated into plant procedures or were in the process of being translated. However, one example of inadequate translation of the design bas's into plant procedures was identified during the mechanical review.
i The CDCs used in the revised MSLB containment accident analyses and SBLOCA analysis are considered design basis characteristics. The team's review of the validity of the MSLB and SBLOCA CDCs determined that there was a failure to translate these design basis characteristics into plant procedures.
As an example, the MSLB containment accident analysis CDC for containment free net volume was assumed to be 1,899,000 cubic feet. However, Engineering Procedure EN-21065, Rev. 3,
" Containment Mass Tracking," dated April 3,1998, does not include an acceptance limit to assure that this CDC continues to be valid.
10 CFR Part 50, Appendix B, Criterion lil, " Design Control," rey' ires that, " measures shall be established to assure that the applicable regulatory requirements s.7d the design basis...are correctly translated into speci:1 cations, drawings, procedures, and instructions." The failure to correctly translate the design hasis, as identified in the FSAR Chaner 14 accident analyses, into plant procedures that incluos an acceptance limit in EN 21066 assuring that the containment free net volume continues to be valid, is a CLn of the design control requirements of 10 CFR 50, Appendix B, Criterion Ill. This issue is considered equivalent to an ICAVP Significance Level 3 finding. (VIO 50-336/98 213-01, Example 1)
Millstone personnel agreed that there was an apparent weakness in the flow of information from new or revised analyses into plant procedures. CR M2-98-2355 was written to evaluate and address this weakness as it applies to this and other examples, and to the generic process for
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handling this type of technicalinformation, as described in the Design Control Manual (DCM).
The team also made two observations about the in-process translation of the design basis into plant procedures:
(1) Inadequate Translation of Design Basic into Plant Procedures for in-Process Tracking Commitments The licensee issued AR-98008632-01 to track the need for providing design basis information for pump Inservice Testing (IST) procedures. Alhough this tracking l
commitment partly validated CDCs applicable to pump IST degradation limits, it did not l
assure that the system operability surveillance procedure (or its equivalent) would validate the CDC flow requirements for the containment spray, charging, and auxiliary feedwater j
systems (usually a non IST function).
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(2) Untimely Update of The Safety Functional Requirements (SFR) Design Basis Document.
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When the System Design Basis Document Packages (DBDPs) were retired and replaced by System Design Summary documents, the SFR document was retained as a controlled and maintained DBDP. In reviewing the validity of CDCs for the MSLB and the SBLOCA accident analyses, the team found that the SFR did not reflect system-specific analyses and modifications performed in support of the updated accident analyses. Although the present design control process (per the DCM) provides for the revision of the SFR, the lack of l
timeliness is considered a potential vulnerability in the design control process, especially in the translation of the design basis into plant procedures.
CR M2-98-2355 as described above, was written to evaluate and address the weakness as it applies to the inspection examples and the DCM process. The CR also includes an I
effectiveness review to ensure that key Safety Functional Requirements Manual assumptions
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are reflected by existing plant configuration and operating practice.
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2.2 Observations and Findinas at Parsons The team identified a minor inconsistency in Parsons'implementatio7 of the ICAVP Audit Plan and Project Procedure, PP-02, " Accident Mitigation Systems Review," as currently documented and as approved by the NRC staff. The inconsistency was in the validation of CDCs associated
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with the systems being reviewed by the Parsons Tier 1 Group. During discussions with Tier 1 and 2 staff, the team determined that the validation of CDCs for Tier 1 systems were being performed using a more informal process than described in the NRC-approved ICAVP Audit Plan and PP-02. However, even though the interface with the Tier 1 group was not as formal as specified in PP-02, the team concluded, after further discussions with both Tier 1 and 2 staff, that the process was still effective in conducting the Tier 2 CDC validation.
Parsons was requested to assure that the process being used did not reduce the effectiveness of the Audit Plan and the Tier 2 process documented in PP-02. Further, Parsons was
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requested to revise the Audit Plan and PP 02 to accurately describe the process utilized for interaction between the Tier 1 and Tier 2 groups to validate the CDCs for the affected Tier 1 systems.
2.3 Conclusions The team concluded that for plant niodifications there were no safety significant concerns with
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the licensee's design control process. However, the specific finding on the lack of translation of accident analyses inputs to plant procedures was a programmatic weakness that had not been adequately addressed in the DCM. The DCM was mainly used by the licensee for the desir,o control of plant modifications. This programmatic weakness effected Unit 2 substantially more than Unit 3 because the licensee had reanalyzed most of the accidents described in Chapter 14 of the Unit 2 FSAR. Millstone engineering personnel agreed that there was an apparent weakness in the flow of information from new or revised analyses into plant procedures.
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CR M2 98-2355 was written to evaluate and address this programmatic weakness.
The team concluded that Parsons' methodology for reviewing and validating the CDCs in plant procedures was acceptable for mechanical systems and components and that Parsons conducted the review in a comprehensive and detailed manner.
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Q 3.0 Instrumentation and Controls (l&C)
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3.1 Millstone Site Observations and Findinas For the CDCs sampled, the team determined that because of the recently revised analyses,
most of the CDCs had not been successfully translated into active plant procedures and
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acceptance criteria. Only 10 of 39 l&C related CDCs were completed and validated by the team. The team identified five CDCs not fully implemented in plant procedures but validated by
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Parsons. These are associated with control element assembly (CEA) drop time and feedwater isolation valve closure time, as discussed further in Sections 3.1.1 and 3.1.2 below.
3.1.1 Control Element Assembly Drop Time The MSLB and SBLOCA analyses assumed that CEA-holding coils would release the rods 0.5 seconds after power to the coils is interrupted and that the rods would be 90 percent inserted (from 180 steps to 18 steps) in the next 2.25 seconds for a total time from power removal until rods were 90 percent inserted of 2.75 seconds. TS Limiting Condition for Operation (LCO)
3.1.3.4, "CEA Drop Time," requires a fully withdrawn CEA drop time of less than or equal to 2.75 seconds from when electrical power is interrupted to the CEA drive mechanism until the CEA reaches its 90-percent insertion position. The TS does not address the two constituents of this time interval described in the accident analysis.
The licensee used Surveillance Procedure (SP) 21010, Rev 5, "CEA Drop Times (IPTE) " to satisfy TS 4.1.3.4 testing requirements. The procedure permitted testing one group of rods at a time with the results monitored by the plant process computer (PPC); the acceptance criterion was that the rods must be fully inserted within 2.65 seconds; otherwise individual rods must be re tested with a measuring and test equipment (M&TE) strip chart recorder. During group rod testing a single rod in the group was also monitored by an M&TE recorder and the acceptance criterion for this rod was relaxed to the TS limit, i.e., s2.75 seconds from power removal until 90-percent insertion. Neither the group drop test nor the individual rod test measured the time between removing power to the CEA and when rod motion began, nor did they measure the time between the start of rod motion and adequate rod insertion. The team noted this information was available on the strip chart recorder records but was not measured.
The failure to translate design requirements (CEA coil release times of s0.5 seconds and rod motion 52.25 seconds)into plant test procedures is another example of failure to translate design requirements into plant procedures, contrary to the requirements of 10 CFR 50, Appendix B, Criterion Ill, " Design Control." This issue is considered equivalent to an ICAVP
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Significance Level 3 finding. (VIO 50-336/98 213-01, Example 2)
The licensee evaluated actual data from the 12 individual rods recorded when rod drop testing was last performed in 1995, and reported the coil release times varied from 0.12 to 0.22 seconds, well within the accident analysis assumption. The licensee initiated CR M2-98-2412 to evaluate whether coil release times needed to be measured for each CEA after refueling.
The team also reviewed the recommended CEA gripper coil testing in the CEA Vendor Technical Manual (VTM) VTM2-150-006A, Rev. 006D, " Unit 2 Magnetic Jack Type Control Element Drive." The team noted the licensee was not performing the maintenance recommended in Sections 6.1.1.4,6.1.2.1.3, and 6.1.2.2.2 of the manual. The licensee initiated
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CR M2-98-2399 to investigate why the vendor-recommended testing had not been incorporated into the control element drive mechanism (CEDM) maintenance procedures. Further NRC review of this issue will be tracked as an inspector followup item (IFI). (IFl 50 336/98 213 02)
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3.1.2 Feedwater Isolation Vajve Closure The SBLOCA analysis assumed the feedwater (FW)-regulating valve would not close until 30 seconds after the reactor tripped. This ensures that adequate heat is removed from the primary plant. In Instrument and Control Procedure (IC) 2426A, Revision 7, "Feedwater Control System Calibration," Attachment 5, "Feedwater Control Calibration Data Sheet," Step 4.16.134.a the acceptance criterion was 3012 seconds. The main FW-regulating valve could close in less than the 30 seconds assumed in the accident analysis.
The team concluded that the failure to translate this design requirement into plant procedures was oflow significance from an accident analysis standpoint. As stated in Section 3.2, Parsons plans to evaluate this further during its review of the new SBLOCA analysis.
3.1.3 Setpoint Program Engineering Work Request (EWR) M2-97-061, "Setpoint Program," was a large project to address the effects of harsh environments on RPS, ESF, emergency operating procedures (EOPs), and other TS-related instrument setpoints. The licensee stated it was not co nmitted to Regulatory Guide (RG) 1.105, Rev.1, " Instrument Setpoints for Safety Related Systems," that would have required the use of accepted statistical methods to account for measurement and instrument uncertainties for RPS-and ESF-actuated features. The team reviewed approximately 10 RPS and ESF setpoint calculations revised under this program.
The team noted that the calculations were a significant improvement over the setpoint calculations used to license the plant and were consistent with licensee specification SP-ST-EE-286, Rev. 6, " Guidelines for Calculating Instrument Uncertainties." SP-ST-EE-286 is a site-wide procedure used to ensure RPS and ESF setpoint methodologies were consistent with RG 1.105. The team concluded that even if Unit 2 was not committed to RG 1.105, the licensee was required to follow SP-ST EE-286 at Unit 2.
The licensee was also participating in a recent initiative of the Combustion Engineering Owners Group (CEOG) to identify the engineering and analyticallimits and bases for non RPS and ESF actuation system (ESFAS) setpoints. These setpoints were not addressed by RG 1.105 but the licensee acknowledged it was important to understand which TS parameters were sensitive to instrument uncertainties.
The licensee stated it was reviewing several DRs associated with instrument uncertainties, including DR-130, " incorrect Value Used for M&TE Term in Calculations," and DR-364,
" Discrepancies in Setpoint and Loop Uncertainty Analyses for HPSI," to determine if the concerns were valid and the impact on the calculation results. The team found that this review was being completed in a thorough and systematic manner.
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The team identified an error in SP 24028, Rev. 6, " Pressurizer Pressure Calibration," Step 2.3.1
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that provided the option of using a 0-2500 or 0-3000 psig gauge to calibrate the 1000-2500 psia pressure transmitters PT-102 A, B, C, and D pressurizer pressure instruments. M&TE such as these pressure gages can exhibit nonlinear behavior at the high and low extremes, and this
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O would not necessarily be detected during normal measuring and testing equipment (M&TE)
calibrations. Industry practice is to not use the extremes of M&TE when calibrating
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important-to-safety devices.
The team questioned the use.of a 0 2500 psig gage for calibrating PT-102A, B, C, and D because it may not provide adequate margin beyond the calibrated instrument range. As a result of this concern, the licensee added AR 98010434 to existing M&TE CR M2-98-1500.
This AR will result in a review of all calibration procedures for RPS and ESFAS setpoints to ensure the calibration range is enveloped and to revise procedures as required. Further NRC review of this issue will be tracked as an IFl. (IFl 50-338/98-213 03)
M&TE has been identified as a problem at Millstone in the past. M&TE lasues were identified as a Unit 1 Significant items List (SIL) item although it was a site-wide problem. The various M&TE lasues raised by Parsons in DRs, the existence of a Unit i SIL item, and related j'
questions raised by the team demonstrate a need for continued improvement in the Unit 2 M&TE program.
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3.2 Observations and Findinos at Parsons The team identified some minor differences between the Parsons' CDC validation and the
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team's effort. These were the result of changes to the licensee's documents between the time l
Parsons reviewed the available data and when NRC reviewed the data. These minor differences include the proposed RPS and ESF TS setpoint d.anges and the status of SP 2604P as a "DO NOT USE" document. One of the differences noted by the team was the CEA drop time test CDCs. Parsons stated that the licensee did not monitor the coil release and actual rod travel times, but Parsons determined this was acceptable based on a review of other data such as post trip reports. The post-trip data reviewed showed neutron flux decreasing 0.4 seconds after the reactor trip signal, and Parsons interpreted this as evidence that the coils released the rods in less than 0.5 seconds. Parsons also stated that if the coils were not releasing the rods within the 0.5 seconds, the licensee would have experienced problems with the group drop time criterion of s2.65 seconds. As there was no evidence that this time was being exceeded, Parsons concluded the coil release and rod travel times were being met.
Parsons was unable to review lC 2426A when evaluating the FW-reguleting valve closure after a reactor trip because the status of the procedure was "DO NOT USE." Parsons reviewed an alternate source, M2-EV-98-0017, " Failure Modes and Effects Evaluation for Feedwater Regulating Valve Bypass and Control Circuit Millstone Unit 2," that stated the FW regulating valves would close in 30 seconds. Parsons indicated it would evaluate this CDC again while reviewing the new SBLOCA analysis report.
3.3 Conclusions in general the l&C CDCs were not included in current approved-for-use plant procedures, but this was primarily because the setpoint program was being revised and the ESF time response procedure was in a "DO NOT USE" status, it is the team's understanding that these procedures will be updated prior to entry into the operating mode for which they are necessary.
The NRC will verify that "DO NOT USE" procedures have been appropriately revised and returned to approved for-use status as necessary to support changes of operating mode as part
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l of the closure process for the Unit 2 SIL item No. 8 " Procedure Adequacy / Procedure Upgrade i
Program,"
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The failure to translate the CEA coil release and rod motion times into plant procedures is the second example of a violation of the requirements of 10 CFR 50, Appendix B, Criterion Ill,
" Design Control."
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The team concluded the Parsons review of the l&C-related CDCs was adequate and sufficiently detailed.
l 4.0 Ooerations j
4.1 Millstone Site Observations and Findinas l
For the CDCs sampled, the team determined that, in most cases, the parameters had been successfully translated into plant procedures and acceptance criteria.
The team noted two exceptions:
(1) As discussed in Section 4.1.4, in many cases the team had to evaluate the requirements and criteria in procedures marked "DO NOT USE." The team considered the parameters verified with these procedures as provisionally valid.
(2) In some cases, Parsons had identified a DR pertinent to the parameter. In these cases, the team concluded the parameter was valid (successfully implemented) with the exception of the DR resolution. The DRs in the operations area concerned issues such as instrument accuracy.
Additionally, the team identified two parameters that did not appear to be successfully implemented in plant procedures.
4.1.1 Feedwater Regulating Bypass Valves The MSLB analysis for containment, ABB CE calculation 006-ST97-C-024, Rev. O, assumed that at power levels greater than 25 percent, the FW regulating bypass valves would be closed.
If the valves were open they might fail to close (as the presumed single failure). The open valve would provide additional feedwater from upstream piping and components, and therefore would potentially exacerbate the peak containment pressure and temperature.
The team noted that it is a common operating practice to use the bypass valves to control steam generator levels (at high power levels) when the main feedwater regulating valves are not functioning properly. In these cases, the main valve is put in manual and the bypass valve is used to controllevel. The licensee stated that,in the past, they had utilized this practice and placed the feedwater regulating bypass valves in manual. The team noted that the operating procedure for the feedwater system, OP 2203, Revision 13," Plant Startup," did not have a prohibition against using the bypass valves at power levels greater than 25 percent.
The failure to have a procedural requirement to keep the FW regulating bypass valve closed above 25 percent power (a critical parameter assumed in accident analysis) is considered an example of a violation of the requirements of 10 CFR Part 50, Appendix B, Criterion Ill, " Design Control." This issue is considered equivalent to an ICAVP Significance Level 3 finding. (VIO 50 336/98-213-01, Example 3)
The licensee issued CR M2 98-2355, dated August 14,1998, to document the problem and its
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resolution. The licensee stated that it considered the condition potentially reportable to the NRC as operating in a condition outside of the design bases. The licensee stated that it would make its reportability determination within 30 days and make a report if appropriate.
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4.1.2 Steam Generator Operating Level The MSLB analysis for containment, ABB CE calculation 006-ST97-C-024 Rev. O, assumed that the initial steam generator level was at 70-percent narrow range (NR) level. The team noted that operating procedure OP 2203, Revision 13, " Plant Startup," allowed steam generator allowed normal operating levels up to 75 percent NR. The increased initial inventory provides more feedwater in the faulted generator, and therefore could potentially exacerbate the peak containment pressure and temperature.
The team referred the matter to NRC technical staff, who stated that the more appropriate
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approach would have been to use the more conservative input value of 75 percent. However.
the staff stated that the analytical methodology used to determine the resulting containment pressure and temperature after an MSLB contained sufficient conservatism such that it is uh!:kely that the consequences of the accident were underestimated using the nominal value.
Also, from a risk-informed perspective, in addition to the low probability of a complete break of a main steam line, it is unlikely that an MSLB would occur when all the important parameters are at the worst-case values for containment pressure and temperature. Based on the above, the team concluded no further review of this issue was necessary.
4.1.3 Auxiliary Feedwater (AFW) Enthalpy CDC The MSLB CDC for the maximum AFW enthalpy is based on 100'F. The latest revision of OP 23198, " Condensate Storage and Surge System," states the maximum allowable condensate storage tank (CST) temperature is 120'F. Operations Form 2669A 1, " Unit 2 Turbine Building Rounds, Outside Areas," also indicates a maximum allowable CST temperature of 120*F. The CST is the water supply for the AFW pumps.
The failure to translate the appropriate AFW enthalpy temperature from the accident analysis into the operating procedure is another example of an improper translation of accident assumptions and design basis into plant procedures, contrary to the requirements of 10 CFR Part 50, Appendix B, Criterion Ill," Design Control." This issue is considered equivalent to an ICAVP Significance Level 3 finding. (VIO 50 336198 213 01, Example 4)
4.1.4 Use of"00 NOT USE" Procedures During the review of operations procedures in the Unit 2 control room the inspection team found that many of emergency operating and power operations procedures were administratively classnbd as "DO NOT USE," based upon having exceeded their biennial review dates. TS Section 6.0.1, " Procedures," states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of RG 1.33 (February 1978). Appendix A of RG 1.33 includes procedures for power operation, procedures for emergencies and other significant events (including plant j
fires), procedures for surveillance tests, and procedures for maintenance.
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TS 6.8.2.c states that each procedure of Specification 6.8.1 shall be reviewed by the Plant Operations Review Committee (PORC) or Station Operations Review Committee (SORC) and shall be approved by the Unit 2 Unit Director or Senior Vice President and Chief Nuclear Officer
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(CNO). Millstone, or be reviewed and approved in accordance with the Station Qualified Reviewer Program, before implementation. TS 6.8.2.c also requires that each procedure be
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reviewed periodically, as prescribed in administrative procedures.
As of August 21,1998, the licensee had not maintained current all of the procedures i
recommended in Appendix A of RG 1.33, failing to review certain procedures periodically, as i
required by TS 6.8.2.c. Specifically, station procedure DC 1," Administration of Procedures and l
Forms," Rev 7, dated August 12,1998, which sets forth requirements for periodic review of
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procedures, allows procedures to be designated as "DO NOT USE"if the required biennial review cannot be completed before the biennial review expiration date. As of August 21,1998, the licensee had designated 144 procedures as "DO NOT USE" because the biennial reviews
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had not been completed. These procedures included the AOP 25; 9 Fire Procedure series and the emergency operating, power operations, surveillance, and mabtenance procedures.
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Station procedure DC 1, page 53 of 104, states that the "DO NO T USE" process is not l
applicable to procedures dealing with medical or fire emergencies.
The licensee decided to defer the required reviews and updates because of limited resources and because most of the station accident analyses were being updated with the latest design information. The NRC staff understands that Unit 2 had been defueled and was in an extended shutdown when procedures exceeded their biennial review date and that information from the revised accident analyses will need to be factored into many of these procedures. The team did not observe any "DO NOT USE" procedure being used (other than simulator training) for safety-related activities. Further, none of the procedures designated as "DO NOT USE" are applicable or necessary with the plant defueled.
The use of "DO NOT USE" on procedures has been an issue in the past with Millstone Unit 2.
A 1991 violation,50 336/91-81-12, identified that more than 100 station procedures had not received a biennial review. A 1993 violation,50 336/93 20 01, identified more than 200 station procedures had not received their biennial review. Also, the facility's intemal quality assurance (QA) organiWon made similar findings. In March 1994, in response to the 1993 violations, the station issued DC-1, Rev.1, (biennial review) that allowed procedures that had not received their biennial review to be placed in a "DO NOT USE" status to ensure that before use, the procedures would receive the required reviews. The facility was in full compliance in June 1996.
The failure to maintain current some 144 procedures that were identified as "DO NOT USE" because they exceeded their biennial review dates, is considered a violation of RG 1.33 and station TS 6.8. This group of procedures included the AOP 2579 fire procedure series and emergency operating, power operations, surveillance, and maintenance procedures. TS 6.8 requires procedure review and management approval and neither is mode dependent.
However, since none of the procedures designated as "DO NOT USE" were required for current I
plant conditions, i.e., no fuel in the reactor vessel, the team considered the significance of this
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violation to be below the level of significance of a Severity Level IV Violation. Therefore, in accordance with Section IV of the NRC Enforcement Policy, this is considered to be a Non Cited Violation. (NCV 50 336/98 213-04)
Also, during the simulator demonstration at the training facility, the team identified that the
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EOPs being used in the simulator for licensed operator training were in draft status that was a
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different revision than those in the Unit 2 control room binders or as identified in site nuclear records. These draft procedures have not been reviewed and approved by the appropriate site
management. Since only approved procedures are allowed for licensing actions, the lack of
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approved procedures prevents the NRC from administering license operator examinations and
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is a sign!ficant training concem.
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CR M3 98-3781 was written to evaluate and address the appropriateness of the "DO NOT
USE" process as it applies to all station procedures and CR M2 98-2414 was written to address i
"DO NOT USE" status of procedures used for licensed operator training and examinations.
4.1.5 Observation of Training Simulator Demonstration The team observed an operating crew respond to both an MSLB and a LOCA scenario on the Unit 2 simulator at the Millstone Training Facility. The team also reviewed the EOPs and performed plant tours. The team determined that the operating crew was very professional, demonstrated a thorough knowledge of the EOPs, and exhibited good communication skills
j during the response to the accident scenarios.
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The review of EOPs involved a verification that the accident analysis assumptions, design
bases, licensing bases, and plant operation conformed with each other when appropriate. The team determined that EOPs 2532, Rev.15," Loss of Primary Coolant," and EOP 2536, Rev.
14 " Excess Steam Demand," were clear, concise and easily readable. EOPs 2532 and 2536 j
are symptom-based procedures derived from the generic CEOG procedure guidance. The
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team found that the licensee appropriately modified the generic CEOG procedure to agree with the configuration of Unit 2. A step deviation document was prepared that described in detail
why and where a deviation from the CEOG approved procedures existed. In general, the deviations were a result of inserting Unit 2 plant specific information for components. Plant-specific instrument setpoints were developed using the setpoint methodology provided in the generic CEOG procedure development documents. In addition a setpoint upgrade program has been completed and incorporated into the Unit 2 EOPs.
4.2 Observations and Findinas at Parsons For the case of the FW-regulating bypass valve, the Parsons engineers stated that according to the information they had, OP-2203, " Plant Startup," did not specifically describe the use of the bypass valves at high power levels. However, since the bypass valves are typically closed above 25 percent power, the Parsons reviewer was unaware of the operations practice. The Tier 2 program did not include con operations oriented review of each critical assumption or parameter. Further, it is difficult to anticipate possible operator actions not precluded by procedures.
4.3
. Conclusions Although the team noted two instances in the operations area in which the licensee failed to adequately translate design requirements into operating procedures, overall the team concluded that the licensee had adequately translated design bases requirements into plant procedures. Further, team found that the licensee trained its operators on EOP implementation and that the EOPs were consistent with the current design and licensing bases. However, the team also determined that the licensee's deferral of the biennial review of EOPs, making "DO NOT USE"was contrary to the requirements of TS 6.8.1. This decision by the licensee was based on the fact that the majority of the accident analyses were still a in progress and to conserve resources during the current extended outage. Further, the EOP revision used in the simulator (Rev.17) did not match the revision used in the control room or in the licensee's
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procedure tracking program. Without approved procedures in place to support licensed operator training, the NRC cannot administer licensed operator examinations.
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The team considered that the Parsons review was comprehensive and at the appropriate level of detail. Although Parsons d,id not identify that the operating procedures did not preclude operation with the feedwater bypass valves open at greater than 25 percent power, this is not a typical nor anticipated operating configuration.
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5.0 Entrance and Exit Meetinas The team conducted an entrance meeting on August 10,1998, for the Millstone Unit 2 Tier 2 inspection. On August 31,1998, the team conducted an entrance meeting at the Parsons offices in Reading, Pennsylvania. During each of these meetings, the team discussed the scope, duration, and expected support requirements for each phase of the inspection.
On October 6,1998, the team leader conducted an exit meeting at the Millstone Training Facility that was open for public observation. During this meeting, the team's findings and observations were discussed. A partiallist of attendees is given in Appendix B.
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e Appendix A List of Apparent Violations, Unresolved items, and Inspector Followup Items
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This report categorizes the inspection findings as violations (VIO), apparent violations being considered for escalated enfqrcement (EEI), unresolved items (URis), or inspector followup items (IFI) in accordance with Chapter 610 of the NRC Inspection Manual. An apparent violation is a matter about which the Commission has enough information to conclude that a violation of a legally binding requirement has occurred. The violation is classified as apparent until the NRC assigns a severity level, and the licensee is given a chance to respond to the NRC's determinations. A URI is a matter about which the Commission requires more information to determine whether the issue in question is acceptable or constitutes a deviation, nonconformance, or violation. The NRC may issue enforcement action resulting from its review of the identified URis. An IFl is a matter for which additionalinformation is needed that was not available during the inspection.
Item Number Type Section(s)
Status Title 50-336/98-213-01 VIO 2.2.1 Open Failure to translate accident analyses 3.1.1 assumptions, inputs, or results into plant 4.1.1 procedures contrary to 10 CFR Part 50, 4.1.2 Appendix B, Criterion Ill.
50-336/98-213-02 IFl 3.1.1 Open Vendor recommended testing not incorporated in control element drive mechanism maintenance procedures 50-336/98-213-03 IFl 3.1.3 Open Use of 0 -2500 or 0 -3000 psig gauge to calibrate 1000 -2500 psia pressure transmitters PT-102 A, B, C, and D, pressurizer pressure instruments.
50-336/98 213-02 NCV 4.1.4 Open Utilization of "DO NOT USE" classification for procedures contrary to RG 1.33 and TS 6.8.
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Appendix B Entrance and Exit Meeting Attendees (Partial List)
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NAME ORGANIZATION
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Northeast Nuclear Enerov Comoany M. Bowling Unit 2 Recovery Officer J. McElwain Unit 2 Recovery Officer P. Loftus Manager, Regulatory Affairs M. Ahern Manager, Design Engineering D. Harris Coordinator, Regulatory Compliance i
J. Fougere Manager, ICAVP R. Necci Director, Configuration Management Program R. Laudenat ICAVP Program Director, Regulatory Affairs S. Brinkman Director, Unit 2 Engineering R. Boehling Asst. Director, Unit 2 Engineering F. Mattioli Supervisor, ICAVP J. Price Director, Unit 2 R. Ewing Supervisor, Design Engineering, Unit 2 K. Fox Supervisor, Engineering, Unit 2 R. Joshi Manager, Regulatory Complian:s, Urit 2 G. Komoski ICAVP inspection Lead, Design Engineering B. Wilkens Manager, Programs and Engineering Standards R. Lawrence Representative, ICAVP R. Bonner Engineering Supervisor, Unit 2 Operations J. Pizzi Representative, ICAVP R. Crittenden Representative, ICAVP M.Bain Manager, Technica! Support Engineering M. Flasch Manager, Recovery Oversight P. DiBeneregio Director A &P, NJclear Oversight M, Healy Lead, Nuclear Cversight Conneebcut Nuclear Enerov Advisory Congjj T. Concannon Representative US Nuclear Reaulatorv Commission E. Imbro NRC/ Deputy Director, ICAVP, SPO P. Koltay NRC/ Chief, ICAVP, SPO R. McIntyre NRC/lCAVP, SPO - Team Leader B.Hughes NRC/ICAVP, SPO - Team Member P. Narbut NRC/lCAVP, SPO - Team Member R. Quirk NRC Contractor-Team Member D. Beaulieu NRC Senior Resident inspector - Unit 2 S. Jones Resident inspector - Unit 2 B-1
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Appendix C
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List of Critical Design Characteristics (CDCs)
No.* Calculation ' Panimater Udtl5al DosisAChainctedstidMMIM$sA Discihline !
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MSLB-CT Core power level =2771.1 MWT for 107. pere snt assuming l&C 4 -
17.1 MWl' from pump heat
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02.
MSLB-CT -
Max. Pressurizer Pressure = 2300 ps't.
Operations
MSLB-CT -
Max RCS Cold Leg temperature = 561.25 @ 102 percent Operations pwr
MSLB-CT-Max RCS Cold Leg temperature = 534.25 @ 0 percent pwr Operations
MSLB-CT Maximum initial RCS Flow = 422,466 Mechanical
MSLB CT Steam Generator mass @ 0 percent power Operations steam = 16,606.7 lbm liquid = 438,181.8 lbm
MSLB-CT SG Mass @ 102 percent power Operations steam = 23,516. 4 lbm
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liquid = 267,330.2 lbm
MSLB-CT Bypass of Feedwater Regulating Valve closes @ ) 25 Operations
percent pwr.
MSLB CT MAX AFW 100*F Operations
MSLB-CT Time until AFW reaches SG a 180 seconds Operations
MSLB-CT CS water temperature 100* F maximum Operations
MSLB-CT RWST Min. Volume for Spray = 26000 gals Operations
MSLB-CT Max. Ultimatt Heat Sink Temp.= 77'F Mechanical
MSLB-CT Initial containment temp 120*F (MAX)
Operations
MSLB-CT Initial containment pressure 14.27 psia (min)
Operations
MSLB-CT Containment Free Volume: 1.899E+6 ft'(minimum)
Mechanical
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MSLB-CT isolate AFW to affected SG in 600 seconds Operations
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MSLB-CT Containment pressure setpoint for reactor trip = 20.53 psia l&C (max)(5.83 psig)
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MSLB-CT Containment High Pressure Reactor trip delay s0.9 l&C seconds max l
MSLB-CT Low SG pressure reactor trip setpoint 384.7 psia (min)
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MSLB-CT Reactor trip delay after low SG pressure trip setpoint <= 0.9 l&C seconds
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Ni C:lculation ' P rim'etsr Critical DisigkCharacteristicNDeh * Disciplinei
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MSLB-CT, insert Rods within 2.75 seconds l&C MSLB RCS,
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CEA Co' trol Rods release time = 0.5 seconds l&C
MSLB-CT, n
SBLOCA, CEA insertion time from 180 steps to 18 steps = 2.25 l&C MSLB-CT, seconds MSLB-RCS l
MSLB-CT ESAS actuation with MSIAS initiates with containment l&C pressure high signal s 5.83 psig (4.8 psig + 1.03 psi uncertainty)
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MSLB-CT FW pumps trip < 1.15 seconds after high containment l&C pressure signal
MSLB-CT FW isolation within 14 seconds after centsinment high I&C l
signal
MSLB CT MSSV Limit Pressure. The 8 SG Safety Valves are Mechanical modeled as one valve that starts to open @ 1030 psia (was 1000 psia) and reaches full open at 1081.5 psia
MSLB-CT ESAS containment spray initiation on containment high-high l&C pressure signal <= 11.08 psig
MSLB-CT Containment Spray pump actuation time, assuming VA-20 I&C failure is 16 seconds
MSLB-CT Cont. Spray pump actuation time for fast transfer failure -
l&C 35.6 seconds l
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MSLB-CT Containment Heat Removal-Containment Spray:
Mechanical Header Fill Time, Train A - 33 seconds l
Header Fill Time, Train B - 26 seconds
33 MSLB-CT Containment Heat Removal-Containment Spray: Minimum Mechanical CS Flow Rate is 1300 gpm/ Pump (one pump operating) 0 percent-50 percent Power Cases
MSLB-CT Containment Heat Removal-Containment Spray: Minimum Mechanical
CS Flow Rate is 2600 gpm total (1300 gpm/ pump)-102 l
percent Power Case l
MSLB-CT Initiate CAR System - Peak Pressure Case: 2 CAR Coolers Mechanical (min.) operating - slow speed i
MSLB-CT Initiate CAR System - Peak Pressure Case Max. Air Side Mechanical Fouling = 0.000 l
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No! Calcula'loE Pirametei CritledDddign C'hsracteristic NSWEP. -
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MSLB-CT Initiate CAR System - Paak Pressure Case: CAR Air Flow Mechanical
= 34,800 cfm/ fan (2 fans operating)
MSLB-CT Initiate CAR System - Peak Preuure Case: CAR Heat Mechanical Removal Capacity - 99.35 MBTU/hr i
MSLB-CT Initiate CAR System - Peait Temperature Case: 4 CAR Mechanical coolers (min.) operating - slow speed
MSLB-CT Initiate CAR System - Peak Temperature Case: Max. Air Mechanical Side Fouling 0.000
MSLB-CT Initiate CAR System - Peak Temperature Case: CAR Heat Mechanical Removal Capacity - 99.35 MBTU/hr
MSLB-CT SIAS on CHPS setpoints s 5.83 psig l&C
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MSLB-CT Max time from CHS to time CAR cooling unit fan is at rated l&C speed with VA-20 failure - 15 seconds
MSLB-CT Max time from CHS to time CAR cooling unit fan is at rated l&C speed with fast transfer failure - 26 seconds
MSLB-C[
Setpoint s 5.83 psig SIAS signal for RBCCW & SW l&C
MSLB-CT Component Cooling - RBCCW-Peak Pressure Case: Pre-Mechanical SRAS Flow to Miscellaneous Users = 1200 gpm
MSLB-CT Component Cooling - RBCCW-Peak Pressure Case Mechanical RBCCW Heat Exchanger Overall Heat Transfer Area
MSLB-CT Component Cooling - RBCCW - Peak Pressure Case Max.
Mechanical Shell Side Fouling = 0.0005
MSLB-CT Component Cooling - SW - Peak Pressure Case: Max.
Mechanical Tube Side Fouling = 0.0005
MSLB-CT Component Cooling - RBCCW-Peak Pressure Case:
Mechanical RBCCW Flow per CAR (Pre-SRAS)=2000 gpm
MSLB-CT Component Cooling - SW-Peak Pressure Case: Min.
Mechanical RBCCW Tube Side Flow = 7570 gpm
MSLB-RCS RCS Flow = 360,000 gpm (nominal) (37,640 lbm/sec @
Mechanical 549'F)
MSLB-RCS RWST boron concentration = 1720 ppm (min)
Operation [
MSLB-RCS AFW Full Flow (2 Pumps) to Affected SG = 1320 gpm Operations (maximum) = 2 x (600 gpm + 10 percent uncertainty)
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MSLB-RCS Low flow trip setpoint in 1.35 seconds - 85 percent of initial l&C
coolant flow l
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'Nor Calculation" Paramete'rMrlUcal Design CharacteristicN DY4Mf8 DIAcipline
MSLB-RCS CEA breakers open in 2 seconds for low coolant flow + 0.65 l&C
seconds
MSLB-RCS Rod insertion begins 2.5 seconds after break I&C
MSLB-RCS SIAS on low Pressurizer pressure at 1576 psia l&C
MSLB-RCS RCS low flow trip setpoint = 85 percent of initial flow l&C
'60 MSLB-RCS Trip delay =0.65 seconds I&C G1 MSLB-RCS Reactor trip on SG pressure = 656 psia l&C
MSLB-RCS SG Low pressure trip delay = 0.9 seconds l&C
MSLB-RCS S!AS initiates on low Pressurizer pressure of 1576 psia for I&C boron injection
MSLB-RCS HPSI delay is less than 25 seconds for boron injection l&C
MSLB-RCS CVCS - Emergency Borate Operations
MSLB-RCS MSIAS initiation on low SG pressure 2476 psia l&C
MSLB-RCS MSIVs closed within 6.9 seconds I&C
MSLB-RCS FRV and FWlV close within 14 seconds of MSIAS initiation l&C
MSLB-RCS isolate Main Steam Line Operations
MSLB-RCS ESAS Actuation on 1576 psia to add inventory I&C
MSLE-RCS ESAS Actuates HPSI within 25 seconds for inventory l&C
MSLB-RCS RCS-P/l HPSI Flow initiate (1 pump available)
Mechanical
MSLB-RCS RCS-PTS Operations
SBLOCA RCS Pump Performance Mechanical
SBLOCA Max SG tube plugging - 500 tubes Mechanical
SBLOCA Max Safety Injection Tank temperature = 106.8'F Operations i
SBLOCA Charging System injection Temperature = 140*F Mechanical
SBLOCA FW isolation valves close in 30 seconds (minimum) after a l&C scram
SBLOCA Reactor Trip TM/LP on minimum floor pressure of 1700 psia l&C
SBLOCA TM/LP Trip delay = 0 l&C
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SBLOCA Minimum SBLOCA ESAS actuation setpoint > 1500 psia I&C
SBLOCA ESAS Actuation - SIAS Initiate: HPSI Flow Delay = 45 Mechanical seconds (maximum)
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o Nol.' Calculatlod Parameter-Critical Desidn Ch'aracteristicWMN@ Discipline
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SBLOCA Charging system response time = 35 seconds max.
Operations
SBLOCA Core Cooling - HPSI Flow - Flow per tables established for Mechanical 5 percent pump degradation (was 5 percent and 7 percent degradation)
SBLOCA Core Cooling - Charging: Charging Pump Flow = 42 gpm Mechanical (was 39.6 gpm)
SBLOCA All RCPs manually tripped <300 Seconds l&C
SBLOCA MSSV Limit Pressure: MSSVs open @ Tech. Spec.
Mechanical Setpoint + 3 percent Tolerance
SBLOCA MSSV Limit Pressure Capacity = 220.6 lbm/sec/ valve.
Mechanical Minimum Blowdown = 6 percent
SBLOCA ESAS initiation on 0 percent SG narrow range level I&C
SBLOCA MDAFW pump initiation within 240 seconds of reaching 0 l&C percent NR level
SBLOCA TDAFW pump initiated manually within 600 seconds l&C
SBLOCA AFW Flow Rate: Minimum Flow - 5 percent and 7 percent Mechanical Pump Degradation Curves i
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- e Appendix D List of Acronyms
AFW-auxiliary feedwater J
ANSI American National Standards Institute AR action request ASME American Society of Mechanical Engineers
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CDC criticaldesign characteristic CEA control element assembly CEDM control element drive mechanism
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CFR Code of FederalRegulations
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CMP _
configuration management plan CR condition report CST --
condensate storage tank ECCS emergency core cooling system EDG emergency diesel generator EMC electromagnetic compatibility
~ EMI electromagnetic interference EOP emergency operation procedure ESF engineered safety feature ESFAS engineered safety feature actuation syetem EWR engineering work request FSAR Final Safety Analysis Report
~FSARCR Final Safety Analysis Report Change Request FW feedwater
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HELB high-energy line break HPSI high pressure service injection I&C'
instrumentation and control I
ICAVP Independent Corrective Action Verification Program IFl inspection followup item -
lST inservice testing requirement LCO limiting condition of operation LER Licensee Event Report LOCA loss-of-coolant accident MCC motor control center MSLB main steam line break MSLBCT main steam line break containment analysis
. MSLBRCS main steam line break reactor coolant system analysis M&TE measuring and test equipment D-1
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NCR nonconformance reports m
NCV non-cited violation NGP Nuclear Group Procedure
'NNECO Northeast Nuclear Energy Company i
NRC U.S. Nuclear Regulatory Commission PAM post-accideM monitoring P&lD piping and instrumentation diagrams PDCR Plant Design Change Request PORC Plant Operations Review Committee PTSCR Plant Technical Specification Change Request RG Regulatory Guide RPS reactor protection system RWST refueling water storage tank SAR safety analysis report SBLOCA small break loss of coolant accident SE-safety evaluation SER safety evaluation report SORC Station Operations Review Committee SP surveillance procedure SWS service water system
' TM/LP thermal margin / low pressure TRM Technical Requirements Manual TS Technical Specification UlR-unresolved item report USQ unresolved safety question VIO violation VTM vendor technical manual D-2
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