IR 05000254/1988200
| ML20155D093 | |
| Person / Time | |
|---|---|
| Site: | Millstone, Quad Cities  |
| Issue date: | 09/07/1988 |
| From: | Haughney C, Konklin J, Vandenburgh C Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20154P316 | List: |
| References | |
| 50-245-88-200, NUDOCS 8810110082 | |
| Download: ML20155D093 (29) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF NUCLEAR REACTOR REGULATION
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Division of Reactor Inspection and Safeguards Report ho.:
50-245/88200 Docket No.:
50-245 Licensee:
Millstone Nuclear Energy Company I
P. O. Box 270 Hartford, Cor.necticut Inspection At:
Millstone Nuclear Power Station Unit I
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Inspection Conducted:
June 13 through June 30, 19853
Team Leader:
M k-T-1-U C. A. VanDenburgh, Sentvt Operations Date Signed Engineer, NRR Team Members:
J. D. Wilcox, Jr., Prisuta-Beckman and Associates E. L. Meils Nuclear Engineers and Consultants, Inc.
D. B. Jarrell, Battelle-Pacific Northwest Laboratory e
0. R. Meyer, EG&G-Idaho Other NRC Personnel Attending Exit Meetings:
J. Konklin, Section Chief. NRR; E. McCabe, Section Chief, Region It M. Boyle, Project Manager, NRR; W. Raymond, Senior Resident Inspector; L. Kolonauski, Resident Inspector
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Reviewed By:
T/7/ff g ames E. Konklin, Chief Dit( 5igned
/ Special Team Support
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& Isetegration Section, NRR l
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Approved By:
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CharlefJ.
aughney Chief ~
KteSigned i
Specia In ection Branch, NRR
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On June 13 through June 30, 1988 an inspection team conducted an inspection of the Millstone Unit 1 Emergency Operating Procedures (EOPs). Millstone Unit 1 is a BWR-3 with a Mark I containment. The objectives of the inspection were to detemine if the E0Ps were technically correct, whether the E0Ps could be physically carried out in the plant, and whether the E0Ps could be correctly performed by the plant staff.
The inspection was accomplished by performing (a comparison of the BWR Owners'
Group (BWROG) Emergenc EPGs) to the Plant Specific Technical Guidelines (y Procedure GuidelinesPSTGs); a comparison of the PSTGs to th of the calculations performed to develop the plant specific curves, values and
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setpoints utilized in the E0Ps; a plant walk-through of all the E0Ps and the
operating procedures (ops) referenced by the E0Ps; a simulation of four emergency scenarios using the plant specific simulator; a human factors review of the procedures and plant operations, and interviews of licensed and non-licensed personnel who utilize the E0Ps and ops; a detailed review of the
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containment venting procedures; and a review of the on-going evaluation of
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i E0Ps.
The inspection was focused on the adequacy of the end product and on a review of the process to develop the E0Ps.
Results:
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I Based on a review of the E0Ps and the supporting calculetions, the inspection l
team concluded that the E0Ps were essentially a technically accurate incorporation of the Emergency Procedure Guidelines with the exception of the
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Primary Containment Control Guidelines.
The Pressure Suppression Pressure and
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Primary Containment Design Pressure limits were incorrectly calculated as a
i result of changes in the calculational assumptions without adequate engineering i
evaluations.
In addition, engineering evaluations to support the development of a realistic limit for the containment venting pressure and the maximum containment water level were not developed.
The plant walkdowns and review of the Plant Specific Writer's Guide (PSWG)
implementation identified numerous deficiencies which the team concluded were the result of generic inadequacies in the PSWG and an inadequate implementation of the verification and validation programs.
Based on these deficiencies and the team's observations during the simulator scenario, the team concluded that the E0P procedures had very poor useability.
In addition, the simulator scenarios identified additional concern with respect to the minimum shif t staffing as defined in Technical Specific 6tions.
The review of containment venting provisions identified that evaluations had not been performed to demonstrate the adequacy of the specified vent path with respect to the operatility of the isolation valves and the the Standby Gas Treatment System under the anticipated accident conditions of high temperature and pressure.
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O TABLE OF CONTENTS EMERGENCY OPERATING PROCEDURE INSPECTION at Millstone Unit 1 Nuclear Power Station
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(Inspection Report 50-245/88200)
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1.0 INSPECTION 0BJECTIVE.........................................
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2.0 ' BACKGROUND...................................................
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3.0 DETAILED INSPECTION FINDINGS.................................
1 3.1 Emergency Operating Procedure (EOP) Program Evaluation.......
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3.1.1 Licensee Verification and Validation of E0Ps..........
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3.1.2 Control of E0P Documentation..........................
l 3.1.3 Interim Changes to E0Ps...............................
3.1.4 Availability of E0P Procedures........................
l 3.1.5 On-Going Evaluation of E0Ps...........................
i 3.1.6 Quality Assurance involvement in PSTG Kaintenance.....
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3.2 E0P Procedure Verification...................................
4 3.2.1 EPG/PSTG Comparison...................................
3.2.2 PSTG/ EOP Compa ri s o n...................................
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3.2.3 Calculation Review....................................
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3.2.4 Adequacy of Writer's Guide............................
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3.2.5 Writer's Guide Implementation.........................
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3.3 E0P Validation Using Plant Walk-throughs....................
3.3.1 Procedu ral Adequa cy of E0Ps...........................
3.3.2 Availability of Special Tools and Equipment...........
3.3.3 Uncon trol l ed Ope ra tor Ai d s............................
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3.3.4 Inaccessible Equipment................................
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3.3.5 Station Material Condition............................
3.'4 E0P Validation Using Plant Simulator.........................
3.4.1 Scenario Description..................................
l 3.4.2 Observations and Conclusions..........................
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3.5 Operator Interviews..........................................
3.5.1 Observations and Conclusions..........................
l 3.6 Containment Venting Provisions...............................
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4.0 KANAGEMENT EXIT MEETING......................................
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Appendix A - Personnel Contacted..................................
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Appendix B - Documents Reviewed...................................
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1.0 INSPECTION OBJECTIVE The inspection team reviewed the licensee's Emergency Operating Procedures (EOPs), operator training and plant systems to accomplish the following objectives in accordance with NRC Temporary Instruction (TI) 2515/92:
(1) Determine whether the E0Ps conformed to the vendor generic guidelines and were technically correct for the Millstone Nuclear Power Station, Unit 1.
(2), Assess whether the E0Ps could be physically carried out in the plant using existing equipment, controls, and instrumentation, under the expected environmental conditions.
(3) Evaluate whrther the plant staff were adequately trained to perform the E0P functions in the time available.
2.0 BACKGROUND Following the Three Mile Island (TMI) accident, the Office of Nuclear Reactor Regulationdevelopedthe"TM!ActionPlan,"(NUREG-0660andNUREG-0737)which required licensees of operating plants to reanalyze transients and accidents and to upgrade Emergency Operating Procedures (EOPs) (Item I.C.1).
The plan also required the NRC staff to develop a long-term plan that integrated and expanded efforts in the writing, reviewing, and monitoring of plant procedures (Item 1.C 9).
NUREG-0899, "Guidelines for the Preparation of Emergency Opera-ting Procedures," represents the NRC staff's long-term program for up E0Ps, and describes the use of a Procedures Generation Package (PGP) grading to prepare E0Ps.
The licensees formed four vendor owner's groups corresponding to the four major reactor vendor types in the United States: Westinghouse, General Electric.
Babcock & Wilcox, and Combustion Engineering. Working with the vendor company and the NRC, these owner's groups developed generic procedures that set forth the desired accident mitigation strategy.
For General Electric Plants, the generic guidelines are referred to as Emergency Procedure Guidelines (EPGs).
These EPGs were to be used by licensee in developing their PGPs. Submittal of the PGP was made a requirement for the Millstone Nuclear Power Station, Snit 1 by Confirmatory Order dated June 12, 1984.
Generic Letter 82-33, "Supplement 1 to NUREG-0737 - Requirements for Emergency Response Capability," required each licensee to submit to the NPC a PGP which included:
(1) Plant Specific Technical Guidelines (PSTGs) with justification for safety significant differences fron the EPG.
(2) A Plant Specific Writer's Guide (PSWG).
(3) A description of the program to be used for the verification / validation of E0Ps.
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(4) A description of the training program for the upgraded E0Ps.
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Plant specific E0Ps were to have been developed that would provide the operator with directions to mitigate the consequences of a broad range of accidents and multiple equipment failures.
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Due to various circumstances, there were long <ielays in achieving NRC approval
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of many of the PGPs. Nevertheless, the licensees have all implemented their E0Ps.
To determine the success of this implementation, a series of NRC inspec-tions are being performed to examine the final product of the prograq:
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E0Ps. A representative sample of each of the four vendor types has been selected for review by four inspection teams from Regions I, II, III and IV.
An additional 13 inspections have been identified at facilities with General Electric Mark I type containments.
The latter inspections are being conducted by the Office of Nuclear Reactor Regulation and include a detailed review of the c'ontainment venting provisions of the E0Ps.
3.0 DETAILED INSPECTION FINDINGS
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3.1 Emergency Operating Procedure (EOP) Program Evaluation A Confinnatory Order, dated June 12, 1984, required the Millstone Nuclear Power Station, Unit 1 (MNPS-1) to submit a Procedures Generation Package (PGP) by May
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13, 1983 and implement Upgraded Emergency Operatir., Procedures (EOPs) by June i
29, 1983. The PGP was submitted in a letter dated May 13, 1983. The PGP
included a Plant Specific Technical Guideline (PSTG), a Plant Specific Writer's
Guide (PSWG), verification and validation procedures, and a description of the
training program for E0Ps.
The PSTG was developed using Revision 2 to the BWROG EPGs. As a result of a request for additional information dated November 30, 1953, MNPS revised the PSTG and provided the requested infonration in a letter dated March 9, 1984 i
The NRC completed the Safety Evaluation of the PGP and concluded in a letter,
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dated September 24, 1984 that the E0Ps for Millstone Unit I were acceptable except for outstanding questions with regard to the adequacy of the Writer's
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i Guide, the verification and validation programs, and the training programs.
In a response dated January 31, 1985, MNPS-1 provided a revised Writer's Guide, i
l comitted to submit a revised verification and validation program by July 31, l
1985 and responded to the questions concerning the training program, t
3.1.1 Licensee Verification and Validation of E0Ps The team attempted to determine whether inadequacies in the licensee's program
of E0P verification and validr. tion may have contributed to the discrepancies
identified in Section 3.3 of this inspection report. The plant specific
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verification and validation of the E0Ps was performed in February 1983 by
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eleven operators during the performance of initial simulator training at the
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I Dresden simulator.
This process was performed in accordance with the verifi-cation and validation program, which was submitted to the NRC in the PGP, but was not incorporated into plant procedures. On September 24, 1984, the NRC approved the PGP by the issuance of a Safety Evaluation (SE) which required the
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resolution of several concerns involving the adequacy of the Writer's Guide and L
the verification and validation program.
In a response dated January 31, 1905,
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Northeast Utilities (hu) revised the Writer's Guide and comitted to revise and
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i submit the verification and validation procedures by July 31, 1985.
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validation and verification procedures were approved by the licensee om May 18,
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i 1988, but had not been submitted at the time of the inspection.
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licensee action is necessary to subm't the validation and verification l
l procedures as previously committed.
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The inspection team determined that although the revisions to the Writer's Guide and the validation and verification program addressed the specific comments of the Safety Evaluation, the revisions were not completely imple-mented.
The revised procedures were used for interim changes to the EOPs, but were not used to ensure that the entire E0Ps implemented the revised guidance, in addition, the team identified that the normal operating procedures which acconplished the directed contingency actions of the E0Ps were never verified or validated because these procedures were not considered to be part of the
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E0Ps.
The team concluded that the failure to implement the revised Writer's j
Guide and verification and validation procedures for the entire E0Ps as well as i
for the referenced operating procedures had significantly contributed to the
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number of deficiencies and negatively impacted the useability of the E0Ps.
Further licensee action is necessary to adequately perform a satisfactory verification and validation of the E0Ps.
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3.1.2 Control of E0P Documentation NUREG-0899 Section 4.4 indicates that the PSTGs are the primary basis of the i
E0Ps and as such should be subject to examination under the overall Quality Assurance (QA) Program.
The PSTGs are required to be accurate and up-to-date and are required to be controlled within the existing plant document control system consistent with administrative procedures and the guidance of Regulatory Guide 1.33. "Quality Assurance Program Requirement (Operation)" and ANSI /
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ANS-3.2-1980, "Administrative Controls and Quality Assurance for the Opera-tional Phase of Nuclear Power Plants."
In the process of reviewing the PSTGs and the E0Ps, the team identified that the original copies of the EPG Calculations (Appendix C), the revised Plant Specific Technical Guidelines (PSTGs) and the original verification and validation sheets were all stored in
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the Control Room Administrative Office as uncontrolled documents.
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calculations and PSTGs were not being formally upgraded and maintained
up-to-dote.
Further licensee action is necessary to upgrade and maintain the
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I 3.1.3 Interim Chances to E0Ps
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The E0Ps had been recently revised by use of Interim Change Notices instead of issuing new revisions.
As a result of the method in which these changes were l
implemented, a high potential for operator confusion existed.
The changes were
I annotated within the E0Ps with a side bar and change number, but were not
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l incorporated into the body of the procedure.
The operator was required to note i
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the side bar and reference the specific changes in the front of the procedure.
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These changes resulted in additional branching and unnecessarily complicated the performance of the procedure.
In most cases the content and corrplexity of i
the change was simple enough to have been incorporated into the body of the i
procedure. Other methods such as full page replacements were not accomplished.
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in addition, the Interim Change Notice approval sheets were posted on the front
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of the E0Ps, thus covering the sumary logic diagram displayed on the front
page of the E0Ps. The cover sheets of the E0Ps were designed to provide a
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visual overview of the procedure content.
Section 2.2 of the Writer *'s Guide
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indicated that the front page of the E0P should be uncovered and that the
approval form of the Interin Change Notice should be attached to the back of i
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the procedure. However, Administrative Procedure ACP QA-3.02, "Station
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Procedures and Forms " paragraph 6.8.1.5.(2) and 6.8.2.5.(2) indicated that the
l change sheet should be placed on the front of the procedure or form, which was
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not consistent with the PSWG. The inspection team noted that the approval sheets for E0P revisions were incorporated on the last page of the procedure in i
accordance with the Writer's Guide.
Further licensee action is necessary to
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incorporate the human engineering guidance of the Writer's Guide intq.the administrative procedures for E0P revisions.
The complexity of the E0Ps was also increased by the number of changes and the failure to correctly incorporate the changes.
Eight of the 12 E0Ps had at least one change notice issued and E0P 572, "Rx Power Control " had three changes outstanding.
In E0P 572, "Rx Power Control." Change Notice No. 3 corrected the scram air header valve numbers in various steps but overlooked the required changes in step 3.6.3 and step 3.5.2.3 which incorrectly refer-enced step 7.10 vice step 7.11 of OP 316, "Feedwater System."
3.1.4 Availability of E0P Procedures
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NUREG-0899 Section 6.1.3 requires an adequate number of hard copies of the E0Ps
available in the control room and at other locations. The practice and policy of MNPS-1 was to have one set of procedures in the control room to limit the amount of paper in the control room and the number of controlled copies to administer. Additional copies of selected parts of the procedures were made by the Shift Supervisor's Staff Assistant (SSSA) if and when required. Although
the inspection team did not identify specific deficiencies, the extensive use of copies of the procedures created the the potential for uncontrolled proce-dures and may delay the implementation of the E0Ps.
Consideration should be given to providing additional copies of the E0Ps for use by personnel other that. the Shift Supervisor.
3.1.5 On-Going Evaluation of E0Ps NUREG-0899 Section 6.2.3 indicates that the licensee should establish a program j
for on-going evaluation of the E0Ps. This program should include: (1)evalua-
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tions of the technical adequacy of the E0Ps in light of operational experience i
and use, trainin experience, and any simulator exercises and control room walk-throughs; (g) evaluation of the organization, format, style and content as
a result of using the procedures during operations, training, simulator
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exercises, and walk-throughs; and (3) evaluation of staffing and staff qualifi-cations relevant to using the E0Ps.
Based on discussions with the licensee's staff and a review of the administrative procedures, the team identified that
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there were no programs which specifically required the E0Ps to be periodically l
reviewed or upgraded as a result of these activities, in addition, the team
verified that Administrative Procedure ACP QA-310. "Preparation, Review ano i
Disposition of Plant Design Change Records " did not require a specific review j
of E0Ps as a process in performing plant trodifications.
3.1.6 Quality Assurance involvement in PSTG Maintenance The team inspected the QA organization involvement in the E0P program. The inspection focused on those policies, procedures and instructions necessary to
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provide a planned and periodic audit of the EOF development, implementation snd j
maintenance process. NUREG-899 Section 4.4 indicates thct as a primary basis of the EOPs, the PSTGs should be subject to examination under the plant's overall Quality Assurance (QA) Program and thus review and control of the PSTGs
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should be included in the established QA Program.
Discussions with Quality
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review of the PSTGs or the E0P program.
The E0Ps were reviewed by the Quality Services Department in the same w6y snat all safety-related procedures were (
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reviewed. The team concluded that the lack of a specific auditing f@ction of
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the E0P program was a management oversight deficiency.
Further licensee at. tion i
l is necessary to include the PSTG and E0P program in the QA program.
3.2 E0P Procedure Verification l
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This portion of the inspection was performed to determine whether the E0Ps were i
prepa' red in accordance with the current PGP and the PSTGs. The inspection i
compared Revision 2 of the BWROG EPGs to the PSTGs. and the PSTGs to the E0Ps.
All differences were identified and reviewed to ensure that safety significant
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deviations were identified in the PGP and that a documented basis existed for
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all deviations.
A review of selected calculations was performed to ensure that i
plant specific values utilized in the E0Ps were correct and perfomed in l
accordance with a documented engineering analysis. Appendix B of this report l
lists the procedures reviewed, i
3.2.1 EPG/PSTG Comparision
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Three differences were identified between the EPGs and the PSTGs. The team (
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concluded that the E0Ps were essentially a correct implementation of the acci-
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dent mitigation strategy for all aspects of the EPGs with the exception of j
l Primary Containment Control Guidelines.
Because an engineering analysis was i
not perfomed to support the development of a Primary Containment Pressure (
Limit (Section 3.2.1.(1)) or the use of alternative methods to measure the
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Primary Containment Water Level (Section 3.2.1.(2)). and because a different
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I pressure instrument was used to measure the Primary Containment Pressure
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Suppression Pressure Limit (Section 3.2.3.(1)). the offectiveness of the (
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Primary Containment Control Guideline was uncertain.
Further licensee action i
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Containment Control Guidelines are currectly implemented.
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J (1) EPG steps PC/P-5 and PC/P-6 identified different values for the Primary
j Containment Design Pressure Limit and the Primary Containment Pressure Limit, however PSTG steps PC/P-5 and PC/P-6 identified identical values l
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for these limits.
E0P training materials and interviews with cognizant
licensee staff indicated that an engineering analysis was not perfomed to
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support a value for the Frimary Containment Pressure Limit which was above i
the Primary Containment Design Pressure.
Further licensee action is necessary to develop a realistic valve for the Primary Containment
j Pressure Limit.
The use of a lower containment pressure limit without adequate evaluation j
and consideration of the effects of this deviation resulted in a confusing
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sequence of operator actions for reactor pressure vessel (RPV) flooding.
I suppression pool spraying and drpell spraying.
E0P 580. "Containment i
Control." step 3.2.6 required initiation of RPV flooding. Steps 3.2.7 and i
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3.2.8 required initiation of suppression pool spraying and drpell l
spraying, if the suppression chamber pressure could not be maintained
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below the Primary Containment Design Pressure Limit or the Primary
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Containment Pressure Limit, respectively.
Because an engineering
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j evaluation had not been perfomed to suppcrt a higher value for the j
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i Prim 4ry Containment Pressure Limit, identical values for both pressure
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limits were used in the E0Ps. As a result, the initiation of RPV flooding l
and spraying of the drywell and suppression pool occurred at the same L
pressure.
This methodology did not represent the correct strattgy of
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Revision 2 of the EPGs, in that RPV flooding was required to be attempted i
q to stop the increase in primary containment pressure before dryvell and
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suppression chamber spraying was attempted. This was a significant i
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deviation from the guidelines of the EPGs which was not documented and a'
justified.
Further licensee action is required to evaluate the correct
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. sequence of these accident mitigation steps.
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(2) PSTG step SP/L-5 developed a maximum Primary Containment Water Level Limit in a method different than specified in EFG step SP/L 3.5.
The EPG method
was based upon the elevation of the highest primary containment vent or
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the water level which imposed a hydrostatic pressure upon the limiting
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containment location equal to the containment design pressure. The PSTG l
utilized a maximum containment water level of 22.2 feet based on the l
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l maximum suppression pool water level indication, because containment water
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I level instrumentation was not available.
This deviation was not con-
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servative, in that the PSTG directed the operators to disregard the l
assurance of adequate core cooling and terminate all injection into the l
RPV at a primary containment water level much lower than required by the j
l EPG.
In addition, this strategy effectively removed RPV flooding as a
method of primary containment pressure control in favor of dowell spray.
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ing when suppression pool water level was at 22.2 feet or higher.
Plant t
specific instrumentation existed in the form of drywell pressure and
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.j suppression pool pressure instruments which could be correlated to the j
j maximum primary containment water level.
Further licensee action is i
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necessary to evaluate and utilire available instrumentation to correctly l
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implement the guidelines of the EPGs.
I (3)
EPG Caution No. 23 stated that drywell spraying was not to be initiated r
with suppression chamber water level obstructing the suppression charrber
to drywell vacuum breakers. The caution was annotated with the statement J
that it was applicable to Mark I containments with internal vacuum
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breakers. The licensee eliminated this caution based on the fact that
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they had external, not internal vacuum breakers. However, a similar j
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j condition concerning obstruction of the vacuum breaker relief path existed g
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licensee because the suppression pool level was not anticipated tu
increase above 22.2 feet which was below the suppression pool to drywell
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Q vacuum breaker suction. However, as discussed in Section 3.2.1.(2), this j
1esel limit was not considered to be correct implementation of the EPGs j
and therefore a similar caution should have been provided to ensure the j
vacuum breaker suction was not blocked when drywell spraying was
initiated.
Further licensee action is necessary to clarify the basis for
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the EPG caution and justify the deletion of the caution, i
j 3.2.2 PSTG/EOP Comparison
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Two differences were identified between the PSTGs and the E0Ps. The inspection
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team concluded that these differences were due to an attempt to be more
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conservative than required by the PSTGs. Deviations from the PSTG during the
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development of the E0Ps war not in accordance with the guidelines of NUREG-0899 j
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and created the potential for undocumented and therefore unjustified deviations from the EPGs.
Further licensee action is necessary to ensure that the PSTG are correctly irrplemented during the development of the E0Ps.
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(1)
E0P 571, "RPV Pressure Control " paragraph 3.3 specified a different pressure (1080 psig) for the minimum SRV lifting pressure than specified in PSTG RC/P-2 (1095 psig) without justification.
The value incorporated into the E0P was conservative.
(2) 'E0P 570, "RPV Level Control." paragraphs 3.3 ano 3.3.1 specified a different level control band (+10 to +50 inches) than specified in PSTG RC/L-2 (+8 to +52 inches) without justification. The control band incorporated into the E0P was conservative.
3.2.3 Calculation Review The inspection team reviewed the calculations and bases for figures and set-points used in the E0Ps to determine if the values were correctly calculated based upon the guidance of the EPGs.
The calculations reviewed are listed in Appendix E of this report. Although several deficiencies were identified with respect to the Primary Containment Control Guidelines, the team concluded that the calculatiens for the remaining guidelines were correctly perfomed and i
reviewed. With respect to the Primary Containment Control Guidelines, the Pressure Suppression Pressurs Limit and the f rimary Containment Design Pressure
Limit were ihcorrectly caiculated because an instrument gage different than specified in the EPGs was used without adequate evaluation of the dev ation.
In addition, as discussed in Section 3.2.1.(1), the Primary Containment Pressure Limit was not calculated W.ause aa angireering analysis was not performed to support the calculation.
All revisions to the calculations were acequately perfomed and docun.ented, however in some cases the original calculations were erased or discarded and
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had not been maintained for reference. As noted in Section 3.1.2, the original calculations and changes have not been controlled as a plant basis document in accordance with the requirements and guidance of NUREG-0899.
Further licensee l
action is required to correct the Primary Containment Control Guideline calculations and to ensure that the original calculations and subsequent changes are controlled and maintained as a design basis document.
The follow-ing deficiencies were noted:
(1)
Pressure Suppression Pressure Limit - Appendix C, Calculation C12 IIditTTieo the maximum pressure which preventeo steam in the suppression
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chamber or allowed emergency depressurization without exceeding the
'
Primary Containment Pressure Limit. The pressure limit was calculated assuming the use of the suppression chamber pressure instror.ent as indi-cated by EFG steps PC/P-2 and PC/P-3, bewever the PSTGs and the E0Ps specified the use of the drywell pressure instrument, this deviation was significant because the two instruments had different, instrument tap i
locations and the c&lculation of the Pressure Supper.ssion Pressure Limit was affected by the location of the instrurent tap. As a result of this
!
deviation, the existing pressure limit curve was incorrect and aHewed
initiatien of drywell sprays in ECP 580, "Containment Control," step 3.2.5 at a higher pressure than required. As indicated in Section 3.2.1.(2).
!
the licensee did not anticipate suppression pcol level increasing to a
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(
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l
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i level which would be affected by this region of the pressure curve,
however this alone was an unjustified deviation from the EPGs.
Never-i i
theless, the Pressure Suppression Pressure Limit as documented in Calcula-tion C12 was incorrect based on the use of the drywell pressure
,
instrumentation as the monitored parameter.
Further licensee action is
'
necessary to correct this calculation.
,
(2) _ Primary Containment Design Pressure limit - Appendix C, Calculation C13
'
identified the maximum containment pressure at which RPV flooding was
'
required. The pressure limit was calculated assuming the use of
!
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' suppression :hamber pressure instrument PR 1602-4A, whose instrument i
sensing tap was located 22.2 feet above the bottom of the suppression l
chamber. E0P 580, "Containment Control," steps 3.2.6, 3.2.7. 3.2.8 and 3.2.9 directed the operator to use suppression chamber pressure instrument
]
PR 1631 C, whose instrument sensing tap was located 2.2 feet above the
!
bottom of the suppression chamber.
Because a different pressure instru-
'
,
l ment was used by the E0P procedure, the Primary Containment Design
!
i Pressure Limit of Figure 6 and the Primary Containment Pressure Limit of i
i Figure 7 in E0P 580 were incorrect since the pressure limits were not
!
I corrected for water levels above 2.2 feet. As a result E0P 500 steps
'
!
3.2.6, 3.2.7, 3.2.8 and 3.2.9 initiated RPY flooding, suppression pool spraying, drywell spraying and primary containment venting at containment i
I pressures below that actually required.
Further licensee action is t
i required to correctly calculate the Primary Containment Design Pressure Limit and the Primary Containment Pressure Limit based on the use of suppression chamber pressure instrument PR 1631-C.
I
(3) Minimun Number of SRVs Required for Emargency Depressurization - Appendix
l j
C, Calculation C17 identified the minimum number of SRVs required to be
!
opened to ensure that the RPV would depressurize.
This calculation was i
based on the assumption that core residual power levels would be approxi-
.
riately two-percent. The EPG calculational guideline for this calculation
<
j identified 3 SRVs as the minimum number of SPVs required to be opened for
,
emergency depressurization.
This value was changed to 4 SRVs with an i
annotation which indicated that the change was a result of "Loss of F.W.
small break." Further licensee action is necessary to document the
!
i; justification for this deviation.
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3.2.4 Adequacy of Writer's Guide l
In order to determine the adequacy of the E0Ps with respect to tne human i
j factors engineering guidance provided in NUREG 0899, "Guidelines for the
!
Preparation of the Emergency Operating Procedures," the inspection team per-l
,
]
formed a review of the Plant Specific Writer's Guide (PSWG) and the E0Ps to l
j detemine the extent to which the P5WG was implemented.
As a result of this i
review, several areas were identified in which the Writer's Guide provided l
]
inadequate guidance or did not address the methodology with which the E0Ps were i
j developed. Further licensee action is necessary to revise the Writer's Guide i
j to include this direction.
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<
(1) Operator Aids - The bad side of many pages in the E0Ps contetned%infoma-
,
]
tion to be used as an operator eid. The PSWG mace no reference to this
,
information and consequently the femat, content and consistency of this l
J infomation was different from one E0P to another.
The information did l
}
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__
_ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ - _
_ _ _ _ _ - _ _ _
_ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _
_______
_ _ _ _ _
..
.
.
not follow the guidance for minimum type style anc was difficult to read.
The required operator actions in response to this information were ambiguous because the information was sometimes presented as infomation (ECP 570 page 3a) or as an action statement (EOP 575 page 4a)..
Additionally, when presented in action statement format, the mixed use of
'AND' and '0R' statements was confusing and contrary to the PSWG.
(2) Step Highlighting - Throughout the E0Ps selected action, contingency and transition steps and notes were highlighted with a box.
The PSWG did not address this method of highlighting and therefore the n.ethod was not Monsistently applied.
For example, E0P 570, "RPV Level Control," which was four pages long, used this method five timest while E0P 580,
"Containment Control " which twenty pages long, did not use this method at all.
(3) Entry Conditions. Throughout the E0Ps, the entry conditions listed on the first page of the E0Ps were not consistently listed and were not separated or distinguished from one another.
The format used for entry conditions in E0P 580, "Containment Control." was different from the femats used in E0Ps 570, "RPV Level Control," and E0P 571, "RPV Pressure Control."
The information provided on the first page was not addressed by the PSWG and as a result was inconsistently incorporated.
(4) Operator Actions - Throughout the E0Ps, operator action steps were incon-sistently formatted because the PSWG provided inadequate guidance for the format of action steps.
For example, PSVG Figure 3 provided a sample procedure page which was incomplete, in that the sample did not show a format for notes, cautions and the various types of action stetements.
PSWG Sections 4.1.2 through 4.1.6 identified five classifications for instructional steps (i.e., contingency actions, verification steps, recurrent steps, alternative actions, concurrent steps), but provided inadequate guidance as to how to fomat them into action steps. The lack of procedurilized methods to implement these different types of action steps forced the procedure writers to create special formatting methods which were not addressed in the PSWG.
'
The action steps were also inconsistently fomatted because the PSWG incorrectly addressed the n,ethodology for a single-column format.
For example, the sample page was in the wrong fomat for single-column E0Ps, in that the left margin was excessive. PSWG Section 3. "Operator Actions," which described the methodology for developing the action steps of the E0Ps was confusing because the instructions appeared to have been developed from a previous PSWG which used a double-column fomat.
In fact PSWG Section 4. "Writing Instructional Steps," referred to an instruction column and a contingency action column which are only used in double-column formatting.
3.2.5 Writer's Guide Implementation
.
The PSWG and the E0Ps were reviewed to ensure that the human factors engineering guidance provided was inecrporated during the development Sf the E0Ps. Numerous deficiencies were noted during this review.
As discussed in Section 3.1, the PSWG was revised as a result of NRC conrents identified in the Safety Evaluation of the PGP.
The inspection team verified that the NRC
. i
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i
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l I
correents were resolved by Revision 1 to the PSWG. Based on the large number of deficiencies noted during the inspection, the team questioned whether the E0Ps were subsequently reviewed to incorporate the revised PSWG. As discussed in
!
Section 3.1.1, the licensee indicated that only specific changes to the E0Ps l
were reviewed in accordance with the revised PSWG and that the entire E0Ps were
,
not reviewed for incorporation of the revised guidance.
In addition, the team l
identified that a Technical Evaluation Report of the E0Ps was issued by
!
Battelle Northwest Laboratory in support of an NRC evaluation of E0Ps on
'
i September 12, 1985. The report identified 34 pages of implementation i
i deficiencies in the E0Ps. Although the results of this review were not l
q formally transmitted to the licensee, the inspection team identified that the
'
'
information was available to the licensee and that the corrective actions for l
}
these deficietces were not implemented.
The inspection team verified that the
.
j these deficiencies had not been corrected at the time of the inspection.
l
t
.
Based on the number of deficiencies noted and the significant potential these i
deficiencies had for operator's confusion, the team concluded that the EOFs did i
,
not have the useability to support the operators actions in an emergency.
!
!
!
Several specific areas were identified which will require further revisions to i
the Writer's Guioe and the E0Ps to resolve. Because of the limited arount of I
l tic.e available for this review, only a few illustrating examples are listed in
each of the areas below.
Further licensee action is necessary to correct not
'
only these specific examples, but the rout cause of the deficiencies, f
i (1)
Inadequate Use of Transitions / Referencing / Branching - E0P 571, "RPV Spray L
Cooling,'" step 3.3.1.7 incorrect,ly branched the procedure to the same step
!
of the procedura.
E0P 577, "Emergency RPV Depressurization " steps
!
i 3.1.4.1 through 3.1.4.3 identified alternate means for the rapid depres-
[
surization of the RPV, however the applicable procedures were not j
'
referenced in the E0P.
E0P 580 "Containment Control," steps 3.2.6 and
3.2.7 referred to Figure 6. "Primary Containment Design Pressure Curve "
i j
and Figure 7. "Primary Centainment Pressure Linit Curve, for the limits
on suppression chamber pressure, however the vertical axis of these l
'
I figures were labelled as Orpell Pressure in psig.
L (2)
Incorrect Use of Logic Statements - E0P 580, "Containment Control." step I
J.E.8 incorrectly incorporated a conditional action statement by using t
!
three '!Fs' before the three conditions.
Step 3.4.3 incorrectly incor-f J
porated a conditional action statemer.t by using ' ifs' before two of the L
four conditions and incorrectly combined four conditions with 'AND'
r
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st atenients.
Step 3.2.5 incorrectly incorporated a conditional action i
statement by combining four conditions with 'AND' statements.
l j
(3)
Ir. correct use of Operator Action Statement _s - Throughout the E0Ps, over-l
ride statements were used to override subsequent action statements.
The
!
_
j use of this overrWe logic was not described in the PSWG, therefore this
[
j methooology was inconsistently incorporated into the E0Ps. As an example,
'
E0P 571
"RPV Pressure Control." contained an action statement irrediately l
)
follcwing step 3.3.1.7 which demonstrated a confusing use of override
!
logic. The act'.on statement did not identify which of the following steps I
'
were subject to overrice (i.e., steps 3.4 to 3.7).
If the action.
l staterent applied to the following steps, the caution relative to cooldowr,
[
l rates should have preceded the action statement.
If the action statement
!
j requires continuation of step 3.3 if the reactor was not shutdown, then
.
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_ _ _ _ _ _ _ _ _ - _ _ _ _
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O the step should have been numbered 3.3.2 or deleted because the logic of step 3.4 precluded executing the action statements of step 3.4.
(4)
Incorrect Use of Type Style - With the exception of E0P 580, "Containment Control." the flow charts represented on the cover sheets of the E0Ps had a smaller type style than allowed by the PSWG.
In addition, the type
'
style used in the operator aid information provided on the back side of some E0P pages (i.e., page 22 of E0P 570) was a smaller type style than allowed by the PSWG, The PSWG specified a letter Gothic, pitch 12, type-writer element for the E0Ps, but numerous deviations occurred throughout
'the E0Ps.
(5)
Incorrect Use of Cautions and Notes - Throughout the E0Ps, there were several examples of incorrect implementation of cautions and notes. One example concerning the resetting of the 120 second timer for the Automatic Depressurization System (ADS) involved several E0Ps.
E0P 570, "Level Control," step 3.3.2 specified that the tiner be reset by an action statement, however the action was applicable throughout the remaining steps.
Upon decreasing level the operator was directed to E0P 576, "Level Restoration," where step 3.4 directed the operator to step 3.7.
The applicable caution concerning the timer appeared on the page following step 3.4 as a boxed override statement and was therefore not referenced before exiting to step 3.7.
Step 3.7 directed the operator to ECP 574,
"Steam Cooling," however there was not a csution, note, action step or override statement in E0P 574 concerning the resetting of the timer.
The PSWG specifically differentiated between precautions, which were applicable to the the entire procedure or procedures, and cautions, which were applicable to the single step or page. However E0P 569, "EOP Administrative Procedure," referred to operator precautions and listed these as cautions.
Caution No. 5 was not incorporated by a note as required by PSWG Section 4.3.
The specification "as soon as possible" in Cautior, ho. 4 was vague and baseo on time rather than a plant parameter as required by PSWG Section 4.1.
E0P 572, "Rx Power Centrol." step 3.5.2 l
followed an incorrectly implemented note which directed the operator to perform E0P 575 concurrently with the followir) steps.
This note was also
+
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incorrectly enclosed with a box which was not addressed as a highlighting method in the PSWG.
-
l (0) Legibility of E0P Ficures - Throughout the E0Ps the Net Positive Suction head (NF5H) figures cid not confurn to the PSWG, in that the horizontal grid lines were less than 1/16 inch and the numbered horizontal lines were
'
not bolder.
In addition, the vertical grid lines were partly illegibic, the line spacings were difficult to interpolate, and the bold lines of the graph did not reproduce properly.
The 1/16 inch spacing for grid lines
,
specified in the PSWG was based upon avoiding saccadic eye movements (i.e., shif ting of the eye focus from one grid line to another and back i
which causes the figure to blur). Most of the other figures in the E0Ps used 1/10 inch spacing, which was preferable.
- i 3.3 E0P Validation Usino Plant Walk-throughs
"
i In order to ensure that the E0Ps ceuld be successfully accomplished, in-plant walk-thruughs for all the E0Ps and referenced ops were perforced. The team
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_ _ _ _ _ _ _ _ _ _ _ _ _
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verified that E0P instrument and control designations were consistent with the
,
installed eauipment and that indicators, annunciators, controls, etc. refer.
2 enced by the E0Ps were available to the operators.
The location and control of
the E0Ps in the Control Room was verified.
With the assistance of licensed i
operators, the team physically verified that activities which would occur
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]
outside of the control room during an accident scenario could be physically accomplished and that tools, jumpers, and test equipment were available to the
,
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operators.
3.3.1 Procedural Adequacy of the E0Ps j
The inspection team identified several deficiencies with respect to the
procedural adequacy of the E0Ps. With the exception of the evaluation of the
!
accessibility of the reactor building (Section 3.3.1 (3)) the deficiencies
appeared to be the result of an inadequate verification and validation of the
'
j E0Ps.
The inspection team concluded that the operators could adequately l
perform the procedures in spite of these deficiencies. However, as discussed in Section 3.1.1, further licensee action is necessary to correct these l
i deficiencies and perform an adequate verification and validation of the E0Ps.
i I
(1) Lack of Procedures
'ne notes preceding step 3.5.2 of E0P 572, "RPV Power
!
a Control," step 7.15 of OP 303, "Reactor Cleanup System," step 3.1.4.3 of i
E0P 577, "Emergency RPV Depressurization," and steps 3.4.2 and 3.5.1.1 of r
{
E0P 578, "RPV Flooding." specified the removal of fuses, jumpering of
contacts or bypassing of interlocks or isolation signals.
However, proce-
-
dures were not developed to identify the applicable contacts, jumpers and
fuses necessary to accurately perform these actiuns.
Based on the need to l
]
accomplish these complex tasks rapidly and correctly in an emergency.
i further licensee action is necessary to develop specific procedures to l
]
provide this information.
J l
(2) Lack of Information - E0P $72 "Rx Power Control." step 3.5.2 referenced
UP7 02, "Control Rod Drive System,* as an alternative method for addition of boron to the RPV. CP 302 Section 7.20 identified the rethodology of boron injection using the Control Rod Drive (CRD) system.
The team confirred that the transfer pump, hose, hose fittings and sodium pentaborate were staged in the reactor building, however the equipment was
<
'
not secured or periodically monitored and therefore had the potential to
,
i become unavailable for use in the E0Ps.
[
t i
E0P 572. "Rx Power Control," step 3.5.2 referenced OP 303, "Reactor
!
I Cleanup System," as an alternative method for addition of boron to the i
Reactor Pressure Yessel (RPV). OP 303 Section 7.15 identified the i
!
wethodology of boron injection using the Reac':or Water Clean-Up (RWCU)
(
slurry tank. The note preceding step 7.15.7 *ndicated that the sodium
t pentaborate solution must be heated to 120 degrees Fahrenheit to dissolve the solution. This guidance was not provideo in the other procedures for
j alternate boron injection. The licensee indiceted that this information
was outdated and incorrect.
In addition, stept 7.15.13 through 7.15.17
!
J were confusing because the filter associated with the recycle inlet,
!
recycle outlet, fill vent and fill drain valves were not identifted.
E0P 572, "Rx Power Control." step 3.5.2 referenced OP 304. "Standby Liquid Control System," as an alternative nethod for addition of boron to the l
I
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l-12-l
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"
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RPV. OP 304 Section 7.6 identified the methodology of boron injection using the hydrostatic test pump to inject into the RWCV system. The
i procedure identified the use of the hydrostatic pump, however the pump and i
i associated connections were not staged and at the time of the wtlkdown
j were in use on Unit 2.
I
E0P 578, "RPV Flooding," steps 3.4.5.2 and 3.5.3.2 required referencing
the temperature near the cold leg reference leg instrument vertical runs.
However, temperature recorder TR 1602-5 on Control Roon Panel (CRP) 925 l
'
identified the inlet and outlet temperatures and not the required i
'inf oma tion.
{
l E0P 578, "RPV Flooding," step 3.4.2.2 specified the CRD System as an
alternate method to add water to the RPV.
OP 306, "Reactor Yessel Head
{
Cooling System," identified the actions required to direct flow to the l
t j
Feedwater System from outside the containment isolation check valves.
The
[
valve lineuo specified did not include closing the feedwater flow control
block valves (1 FW-4A, 1 FW-4B and 1 FW-4C) which was required to prevent j
'
backflow to the condenser.
.
l l
(3) Reactor Building Accessibility - NUREG-0737, "TM! Action Plan," Item II.D.2 requireo the licensee to evaluate the anticipated radiation levels in secondary containment based on the design basis.0CA. This infomation
.
l was not available for on-site review by the team.
Therefore the i
inspection team did not review the post accident radiation survey map to l
ensure that remote operations were not prohibited by environmental condi-
tions.
Discussions with the licensee's engineering staff indicated that
'
the reactor building would be inaccessible following a design basis LOCA j
I j
with the assumed source tem and that contingency actions directed inside i
{
the secondary containment following a LOCA would not be possible. The L
licensee had established procedures for the estimation of in-plant dose i
rates and these procedures would be implemented prior to perfoming the
contingency actions. However, further evaluation by the license is
i required to ensure that the contingency actions of the E0Ps are capable of l
l being perfomed under anticipated accident conditions.
l l
(4) _ Referencing Errors in Procedures - The inspection team identified 2e
!
l following discrepancies in referencing during the review and walkdown of
!
!
the E0Ps.
As indicated in Section 3.1.1, the team concluded that these
!
j errors were the result of an inadequate implementation of the verification i
program.
i l
a)
E0P 571, "RPY Pressure Control," step 3.3.1.6 referred to OP 303,
[
"Reactor Cleanup System," without specific reference to the
-
l applicatle procedure step.
l
!
b)
ECP 572, "RPY Power Control " step 3.5.2.1 referred to OP 302, i
"Control Rod Drive System," without s M cific reference to the
,
[
applicable procedure step.
.
t
!
c)
E0P 577, "Erergency RPV Depressurization," steps 3.1.4.1 through
[
l 3.1.4.3 identified alternate reans for the rapid depressurization of i
l the RPV but did not reference the applicable procedures.
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d)
The caution preceding E0P 580, "Containment Control," step 3.4.2
!
incorrectly identified Temperature Instrument T! 1602-5A on CRP 903.
The correct temperature instruments were TI 1602-6A and Tl 1602-68.
[
,
I e)
E0P 572, "Rx Power Control " step 3.5.2.3 incorrectly referenced OP I
316. "Feedwater System," Section 7.10 vice Section 7.11. This error i
,
i was the result of the implementatien of Interio Change No. I to OP
316 without an associated change to E0P 572.
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l (5)
Incorrect / Inadequate Labelins - The inspection team identified numerous l
i examples of incorrect or inacequate labeling during the walk-throughs.
l The team concluded that more attention is needed to identify and correct
this apparent generic problem with inadequate plant labeling.
J l
a)
E0P 570, "RPV Level Control." step 3.3.2 and E0P 572, "Rx Power
>
Control " step 3.5.1 identified an "APR Timer Reset Button," however
,
j the pushbutton was actually labeled "120 Second Timer."
l b)
E0P 570, "RPV Level Control " step 3.3.2 identified an "APR f
Auto-Blowdown A/C Interlock," however the actual annunciator was t
'
j labeled "Auto Blowdown System A/C Interlock."
i
>
'
c)
E0P 571, "RPV Pressure Control " step 3.3.1.5 required the operation
i of CR0 valves 1-hS 1A, 1-HS-1B and 1-HS 4 which were not labeled.
'
The valves were subsequently labeled by the licensee during the
j inspection.
!
!
c)
E0P 572, "RPV Power Control," step 3.6.7.1 required the operation of
,
!
Hydraulic Control Unit (HCU) vent valve CRD-F102 which was not l
l labeled with the identification of the HCU. The valve was subse-i quently labeled by the licensee during the inspection. Step 3.5.1
,
referred to the "APR Auto-Blowdown A/C Interlock" which was labeled.
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'
"Auto Blowdown Sys A/C Interlock." Step 3.5 referred to OP 304,
"Standby Liquid Control System," in which step 7.3.1 positioned the
,
j Standby Liquid Control handswitch in the position of either "System
,
1" or "System 2."
The "System 2" label on the handswitch was i
l
,
illegible because the white lettering was missing.
-
I e)
E0P 573, *RPV Spray Cooling," step 3 identified the pen recorder on (
CRP 925 as PR 1602 9, however this recorder was not labeled.
In
[
,
i addition, the identificatien of the recorder pens was confusing.
!
l I
f)
E0P 576, "RPV Level Restoration," step 3.3.7 identified valve 1MW 920
!
(ESW to ECCS Crosstie) which was not labeled. The valve was l
subsequently labeled by the licensee during the inspection, j
i t
j g)
The caution preceding E0P 580 "Containment Control." step 3.4.2 t
Ya may or GEMAC)ype of level indicator (i.e. narrow or wide range identified the t
i
, however the specific instruments were not
!
l j
identified in the E0P.
!
j
- e l
h)
OP 302, "Control Rod Drive System," step 7.20.6 referred to the CR0 B t
suction filter vent valve which was not labeled.
F I
I i
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j-14-i l
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. _ _ _ _ _
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1)
OP 303. "Reactor Cleanup System," step 7.15.4 identified valve 1-CV-F4 which was not labeled. Also, steps 7.15.5 and 7.15.10 referred to different valve numbers for the same valve (i.e.,
1 -N-64 ).
j)
OP 304. "Standby Liquid Control System," step 7.5.2.4 required the operation of SLC valve 1 SL-31 which was not labeled.
This valve was subsequently labeled by the licensee during the inspection.
(6) Precision / Readability of Meters - The inspection team identified a few
' minor deficiencies with respect to the adequacy of the control room instrumentation.
The rated condensate /feedwater flow was 7.9E6 Lbm/hr, however the chart recorder on CRP 905 was marked in graduations of 1 through 10 without units.
The rated CR0 pump flow was 200 gallons per minute (gpm), however the control room gages indicated up to only 100 gpm and E0P $70, "PPV Level Control." step 3.4 utilized the full flow capacity of the CRD system. Temperature Indicator ;I 1602-6A indicated in bulk I
(averaged) temperature and could not be correlated to the affected level instrument as required by E0P 580, "Containment Control." step 3.4.2.
!
Although these deficiencies were relatively minor, a successful Detailed
'
Control Room Design Review (DCRDR), required by NUREG 0737, "TMI Action Plan," would have identified and corrected these items.
In order to evaluate the adequacy of the PGP submittal, the KRC requested in a letter dated November 30, 1983, infomation regarding the process for identifying the information and control requirements of the operators and a descrip-tion of the process used ta deterinine the availability and adequacy of the instrumentation and controls to meet the identified needs of the E0Ps.
In
,
a response dated March 9, 1984, the licensee indicated that a DCRDR would be performed in accordance with NUREG-0737 Supplement 1.
The team identi-fied that the DCRDR was not completed and that control room walk-throughs for the DCRDR were scheduled for February 1989, in the absence of a completed DCRDR. further licensee effort to ensure the availability and the adequacy of the instrumentation and controls of the control room is necessary.
3.'3.2 Availability of Special Tools and Equipment
-
Several specific examples were identified in which equiprent or infomation was not available which could affect the perfomance of the E0Ps and directed acticns of the ops.
Based on the training and experience of the eterations staff, the team concluded that the E0P actions could be satisfactorily accomp-lished. However, based on the need to provide procedures which can be cor-rectly implemented by a newly qualified operator and the guidance of AUREG 0899. "Guidelines fur the Preparation of Erergency Operating Procedures."
the team concluded that there was significant potential fer operator confusion
'.
which tray affect the perforrance of the procedures.
Further licensee action is necessary to provide the required equipment or information to ensure that operator confusier will not exist during the perforrr.ance of these prvcedures, j
(1)
E0P 572 "RPY Fower Control," directed the venting of the CRD withdraw line through vent valve CRD-F102 for each Hydraulic Control Unit (HCU) ir.
the event the control rod was not inserted below rosition C4.
Personnel safety equipn4nt (i.e.. high temperature gloves and face shield) was not-15-
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provided to support performance of this procedure. Without su.c equip-ment, the ability to rapidly vent multiplt HCUs under the anticipated conditions of venting high pressure and temperature reactor coolant was questionable. A high pressure hose used to charge the HCU accumulators was available, however the hose was not rated for the high temperatures anticipated.
In addition, based on the length of the hose provided, an effective method to direct this effluent to the floor drains as specified in the procedure was not provided.
(2) E0P $76. "RPV Level Restoration." and OP 304. "Standby Liquid Control
' System." step 7.5.2.1. specified the connection of the Fire System to the Standby Liquid Control (SLC) drain valve as an alternate injection method.
A special adapter was required to make this connection however this adapter was not previously staged nor available. The City /Well Water System was also specified as an alternate injection method, however this water source was not available in the Reactor Building. OP 304 ster 7.5.1 identified sea water as an alternate injection method. This method required connecting hoses from the Reactor Building Heat Exchange Service Water header (Reactor Eu11 ding 2nd level, east side) to the SLC test tank (Reactor Building 4th levtl. west side), however, the length of hose required was not readily available.
In addition, the inspection team noted during the simulator scenarios that pumpers from local fire stations wert utilized by the operators, however this alternate method of injection was not specified by the procedure.
(3) E0P 577. "Emergency RPV Depressurization." step 3.1.4.1 referred to OP 317. "Main Steam System." for rapid depressurization using the Main Turbine Bypass Valves and required 4 jurpers for bypassing the VS!Y Low Low kater Level Trip.
The inspection tear identified that only 2 jumpers were availaole in the E0P tool box located in the control roce.
In addition. E0P 577. "Emergency RPY Depressurization." step 3.1.4.3 referred to OP 306, "Reactor Vessel Head Cooling System," for rapid depressurization using the CRD Head Spray System. OP 3C6 had a caution not to exceed a RPV bead to flange differential of 145 degrees Fahrenheit which was not applicable in emergency conditions, but which was not procedurally overridden.
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Durirg the walkdcwns the team identified a confusing practice of using multiple types of locks for locked valve control.
This necessitated the use of ruitiple keys on the operator's on-rhift key ring. The lack of corresponding identift-cation between the keys ant locks presented an additional potential source of confusion. The Operations Superintendent indicated th6t this was an undesired practice and that further action would be taken to resolve this concern.
3.3.3 Uncontrolled Operator Aios As a result of the E0P walkthroughs, the inspection team identified that the speci6 equipment provideo to support E0P performance was not periodically 4udited or administratively controlled to ensure that the special equipment was available.
For example. E0P 570, "Rx Power Control " referenced OP 302.
"Control Rod Drive Systen." 0F 303. "Reactor Cleanup System " OP 304,45tendby Liquid Control System." and 0F 316. "Feedwater System." as alternative methods for addition of boron into the reactor pressure vessel (RPV). Each of these procedures provideo inadequate instructions cn how to prepare an injectable-16-
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solution of the maximum boron concentration because the correct amount of
i sodium pentaborate required to be added to the various tanks was not provided
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in the procedures.
This infortation was provided on an operator aid which was l
J attached to a pre-staged transfer pump, however this operator aid was not referenced by the procedure and there was no method to ensure the availability
of the aid. Discussions with the Operations Superintendent identified that nort of the staged equipeent for the E0Ps was periodically audited to ensure
j continued availability. Further licensee action is necessary to t
administratively control the equipment staged for the performance of the E0Ps.
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As s' result of verifying that operator aids posted on plant instrumentation and
i control panels were the latest revision and administrative 1y controlled, the
inspection team identified that operator aids were not appropriately controlled
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to ensure their accuracy and availability. OP 261, "Control of Operator Aids."
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step 4.3.1. Indicated that operator aids which contained persanent information
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which was not anticipated to change were not required to be controlled.
However, the inspection team identified several uncontrolled aids which i
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contained information which could be changed and therefore should have been I
controlled as an operatur aid.
For example, a red Bakelite nameplate on CRP I
905 contained Technical Specification liraits for the Suppression Chamber level
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and OP 316. "Feedwater System," Figure 10.1 "Vessel Level Indication," on CRP l
l 925 detailed various RPy levels which were potentially subject to change.
l One example was noted in which a controlled operator aid was incorrectly l
changed.
Operator Aid No.1-87 posted in the Reactor Building near the l
Isolation Condenser identified the Isolation Condenser Level Peter Correction
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Chart. A pen and ink change to the operator aid posted in the Reactor Building
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i did not correspond to the changes made in the Operator Aid Log Book locatec in
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the control room.
Further licensee action is necessary to identify and l
l administrative 1y control all operator aids to ensure that the aids are avail-able, remain up to-date and have not been incorrectly revised.
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j 3.3.4 Inaccessible Equipment
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E0P 570. "RPV Flooding " step 3.4.3.4 required increasing water injection into
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the RPY by using the Essential Service Water (ESW) Systen in accordance with OP
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l 335. "LPCI Containment Cooling System." OP 335 step 7.6 directed the operator
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i to close valve 1-LPC-21 and open valves 1 LPC-19 and 1-LPC-20 to establish ESW
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fit to the Low Pressure Core Injection (LPCI) system.
The valves were located
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In order to operate the valves,
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the operator was required to remove the nine pit covers which were each held in i
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place by four bolts. The covers were corroded and imovable using normally l
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i available tools. The operator eventually' gained access to the valves because
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i one cover was missing three bolts and the fourth was not corroded. Although j
access to the valves was obtained, a high potential existed that the valves would not be accessible in the future.
Further licensee action is necessary to
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3.3.5 Station Material Condition I
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The inspection team reviemed the material condition of the station during the
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plant walk-throughs and ensured that necessary equipment and components were
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accessible and functional.
The overall material condition of the plant appeared to be good and all material deficiencies identified were compensated for by the operators. The team did not observe any interferences in the i
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reactor building, such as scaffolding or maintenance activities, which interfered with operator Etions.
The team verified that emergency lighting was available for EP operator actions and did not identify any discrepancies.
As discussed in Secins 3.3.1.(5) and 3.3.1.(6), the team noted that. labeling is required to b 3 and the DCRDR program, which is expected to
adequately addi ul room labeling, was not completed.
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3.4 E0P V ising Plant Simulator Accident scenar
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developed and conducted utili:ing licensed operators and the plant soer
.c simulator to ensure that the E0Ps could be correctly implemented under emergency conditions.
The accident scenarios:
determined whether the E0Ps provided the operators with sufficient guidance such that their required actions during an emergency were clearly outlined; verified whether the E0Pt caused the operators to physically interfere with each other; verified that the procedures did not duplicate operator actions unless required; and verified that transitions from one E0P to another or to other
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proce6 res were accomplished satisfactorily, i
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3.4.1 Scenario Description The inspection team developed four simulated accident scenarios. All were selected to exercise parallel E0P paths and contingency procedures, with a spacial emphasis on reaching and utilizing the containment venting procedure.
The specific paths were designed to invoke PRA-based risk significant operator actions as a means to demonstrate E0P adequacy.
The first scenario identified the operator's roles and nomal methods of communication and confirmed the inspection team's assignments for observation.
Two of three condensate pumps were tripped from 100-percent power, which caused the two operating feed pumps to trip on low suction pressure and a subsequent reactor scram on low RPV water level. Operator actions were to verify the reactor scram, place the mode switch in shutdown, rapidly shut the MSIVs, and recover RPY water inventory using feedwater injection.
The second scenario exercised the steam cooling E0P under low RPV water level conditions.
In order to remove all sources of core makeup, all off-site
sources of electrical power were removed as a result of a lightening strike coincident with a failure of the Isolation Condenser, Gas Turbine and both Diesel Generators. The transient comenced at 100-percent power, as a result of a trip of the generator output breakers, leaving the plant with only DC battery power.
The RPV pressure and lev 11 control E0Ps were entered and
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utilized along with Off-Normal Procedure ONP 503C, "Station Blackout." The
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MSIVs were shut, with a subsequent attempt to initiate the isolation condenser.
When RPV water level decre:, sed to the top of the active fuel, E0P 574, "RPV Steam Cooling," was entered. Limited electrical power was restored via the diesel generator and a controlled restoration of RPV level was effected using E0P 577, "Emergency RPV Depressurization," E0P 576, "Level Restoration," and E0P 570, "Level Control." Plant recovery then followed normal procedures.
The third scenario exercised as many simultaneous E0Ps as possible and culmi-i nate in containment venting.
In order to ensure an adequate energy deposition to the containment, a complete ATW5 including failure of the Standby Liquid Control (SLC) System and the Isolation Condenser was initiated by the loss of-18-
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three of the four Main Condenser Circulating Water pumps. With the reactor initially at 100-percent power, a rapid loss of condenser vacuum resulted in a turbine trip and subsequent reactor scram.
Because the Main and Isolation Condensers were unavailable, approximately 50-percent reactor power was dumped to the Suppression Pool through the Safety Relief Valves (SRVs).
With the resulting incraase in Suppression Pool and Drywell pressure and temperature, three sections of E0P 580, "Containment Control," E0P 575, "RPV Level /Rx Power" and E0P 572, "Rx Power Control" were implemented simultaneously.
Continued containment pressurization above the Heat Capacity Temperature Limit (HCTL)
required emergency RPV depressurization in E0P 577, "Emergency RPV Depre'ssurization," and containment venting in E0P 580, "Containment Control."
The fourth scenario demonstrated the method utilized by the licensee to respond to a secondary containment high radiation and temperature condition.
In order to produce an unisolable leak from the RPV to the secondary containment, a failure of the scram discharge header drain line was initiated following a spurious scram.
No evidence of the LOCA was evident until high area radiation and temperature alanns were received and the alarming area was identified. The attempt at scram reset was unsuccessful and the leak was determined to be unisolable.
ONP 509, "Excessive Radiation Levels," and ONP 516 "High Energy Pipe Rupture," were entered which required a controlled depressurization and cooldown of the RPV.
E0P 577, "Emergency RPV Depressurization," was not entered.
3.4.2 Observations and Conclusions Overall crew response and E0P implementation was generally good and Sas considered to be due in large part to the depth of training and expr ience -f the operators.
In each scenario, the operator's immediate actions were taken correctly before the E0Ps were referenced.
The E0Ps were implemented accurately with two exceptions.
The first example involved a missed action step due to poor placekeeping methods and is discussed in Section 3.4.2.(1).
The second example involved a misinterpretation of the action step and is discussedinSection3.4.2.(2).
(1) Placekeeping Method - During the third scenario involving a full ATWS, alternate control rod insertion by venting the Hydraulic Control Unit (HCU) withdraw header was not performed.
Discussion with the operators following the scenario indicated that these action steps of E0P 572, "Rx Power Control," were overlooked.
This error suggested that during a high degree of abnormal and complicated E0P execution, placekeeping in the E0Ps was difficult.
The team observed that the operators used multiple stick-on notes to identify their place in the E0Ps. Although the PSWG indicated that short verification spaces in front of each E0P action statement were provided for placekeeping, the operators did not use this method.
Further discussions with the operators identified that the operators were unaware of this placekeeping method and would not use the verification spaces in an crergency. Based on the operator's difficulty in maintaining their place and the missed actions, further licensee action
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is necessary to identify, train and procedurally support an effective placekeeping method.
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(2)
Control Room Responsibilities - During)all four scenarios, the team observed that the Shif t Supervisor (SS maintained direct control of the
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Control Operators (CO) and directed the performance of the E0P actions.
The SS was involved in the performance of the E0Ps to the extent that he d1rectly monitored plant parameters and in one example obtained meter readings at a back panel of the control room.
The Senior Contrql Operator (SCO) used the E0Ps as a verification of the directed actions of the SS and was generally not in direct control of the C0s during the scenarios.
The inspection team concluded that the use of the E0Ps as a verification method instead of a conmand and control document contributed to the misinterpretation of E0P 572, "Rx Power Control " step 3.4.1.
This step required termination and prevention of all injection into the RPV, however the operators slowly decreased feedwater flow to the RPV. This misinter-pretation of the E0P action step resulted in higher reactor power levels and more energy deposition into the primary containment suppression chamber.
The use of the E0Ps by the SCO to verify the directed actions of the SS conflicted with the requirements of MNPS-1 Administrative Control Procedure ACP 6.01, "Control Room Procedure," and Unit 1 Departmental Instruction 1-0PS-1.09, "Conduct of Operations." These procedures indi-cated that the SCO should direct the actions of the E0Ps with the SS maintaining a broad overview of the "big picture" and not involved in direct control board manipulations.
Further licensee action is necessary to appropriately define and irrplement the control room responsibilities.
(3)
Immediate Operator Actions - During the performance of the first scenario involving the loss of main feedwater, the operators imediately isolated the MSIVs in order to conserve RPV water inventory.
Although it was not clear whether this action occurred prior to entry into E0P 570, "RPV Level Control." further discussions with the Operations Superintendent indicated that this action was an appropriate response to the loss of feedwater because MNPS-1 did not have an alternate source of high pressure injec-tion.
The team was concerned that this accident mitigation strategy was a potential deviation from the EPGs which was not addressed by the E0Ps.
Although conservation of RPV level was desired and addressed by ONP 503C,
"Station Blackout," E0P 570, "RPV Level Control," did not require MSIV closure until the low RPV water level isolation trip was reached.
Further licensee action is necessary to evaluate this potential deviation from the EPGs.
(4) Secondary Containment Control - During the performance of the fourth scenario involving a unisolable leak to the secondary containment, the l
inspection team noted that entry into E0P 577, "Emergency RPV
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Depressurization," was not directed by ONP 516. "High Energy Pipe Rupture." A controlled cooldown was performed for approximately 92-degrees and halted to allow assessment of the reduced pressure leak condition.
The licensee had not upgraded their E0Ps to the guidance of Revision 3 of the EPGs and therefore did not have an E0P for Secondary Containment Control. The use of ONP 516, "High Energy Pipe Rupture," for
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response to secondary containment high radiation levels and temperatures was in effect a significant deviation from the Revision 3 EPGs which was not evaluated or justified.
Further licensee action is necessary to justify this deviation.
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(S) Minimum Shift Staffing - Communications outside the control room (dispatcher, plant management, NRC, and Emergency Plan notifications) were simulated in the scenarios by the Shift Supervisor's Staff Assistant (SSSA). The duties of the SSSA were defined in ACP 6.01, "Conttol Room Procedure," and Departmental Instruction No. 1-0PS-2.01, "Shift Assign-ments and Schedule," however the SSSA was not required to be part of the shift manning specified in Departmental Instruction No. 1-0PS-1.09,
"Conduct of Operations." Discussions with the operators indicated that the required actions of the E0Ps would take precedence and that the required notifications could not be accomplished in a timely manner in the
' absence of the SSSA. The operators also indicated that the previous shift SSSA would be held over in the event the on-shift SSSA was not available.
The E0P simulation demonstrated that the shift crew manning (including the SSSA) could implement all the actions of the E0Ps and perform the required notifications. However, the team remained concerned that that the SSSA was not specified in the shift manning of Departmental Instruction No.
1-0PS-1.09 and that additional personnel beyond the Technical Specification Minimum Shift Crew would be required to perform the required actions of the E0Ps and the Emergency Plan.
Further licensee action is necessary to revise the Departmental Instructions and Technical Specifications to include the position of the SSSA.
(6) Control Room Environment - During the scenarios, the team noted that the noise level of the process computer line printer was relatively high and had the potential to affect the ability of the operators to effectively comunicate.
Further licensee action should be taken to minimize this distraction.
The team also verified that a sufficient work area was provided at the SCO's desk to use the multiple procedures required during the scenarios.
Although sufficient copies of the E0Ps were available for use in the control room by the SCO, there were not additional copies of the E0Ps available in either the simulator or the control room. As discussed in Section 3.1.4, multiple copies of the procedures may be required to accomplish directed actions outside the control room.
Further licensee action should be taken to evaluate the availability of procedures for
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local actions.
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3.S Operator Interviews Interviews were conducted by the human engineering member of the team on a one-to-one basis with individual members of the plant staff as classified below:
Job Classification (License)
Number Shift Supervisors (SRO)
Supervising Control Operators (SRO)
Control Operators (RO)
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Senior Training Instructor (Certified SRO)
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A four page interview guide with eight major topics was used for each interview and was reviewed by both parties.
The operators were encouraged to volunteer coments which were relevant and were advised that the objective of the-21-
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interview was to develop information on the effectiveness of the E0Ps and not to examine the qualifications of the individual. The lengths of the individual interviews were approximately one hour.
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3.5.1 Observations and Conclusions (1) Role / Task Definition - The operators described two different assignments of responsibilities relative to execution of the E0Ps. One method was that the SCO was in direct control of the C0s and responsible for the
, directed actions of the E0Ps with the SS maintaining an overview of 'ie plant status. The second method was with the SS in direct control of the plant and the SCO verifying the performance of the E0Ps. As discussed in Section 3.4.2.(2), the second method conflicted with the licensee's administrative procedures.
(2) _Placekeeping - The operators agreed that placekeping was a major area of concern. A short blank line to the left of each action step was provided for placekeeping as a result of the NRC Safety Evaluation comments, however the operators did not use this method during training and indicated that they would not use this method during an actual emergency.
The operators used small stick-on labels to temporarily mark their place in the procedure. As discussed in Section 3.4.2(1), further licensee action is necessary to identify, train and procedurally support a preferred and acceptable method of placekeeping.
(3) Technical Adequacy and Use of E0Ps - The operators had high confidence in the thennal-hydraulic validity and the general useability of the accident nitigation strategy provided by the BWR0G Emergency Procedure Guidelines.
This confidence was tempered by the realization of the limits on time available for operator actions in the first ten minutes of the event and the complexity of the networking of operator actions among the entire set of E0Ps. The operators indicated that they relied on their training for operator actions until the E0Ps could be synchronized with plant status.
The inspection team concluded that the stated need of the operators to rely on their training for operator actions was due in large part to the complexity and difficulty in using the E0Ps and was the direct result of an inadequate verification and validation program discussed in Section 3.1.1.
(4) Training - Each operating crew was scheduled for 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> per year on E0P scenarios during simulator training.
In addition, some entry into the E0Ps was included on other scenarios, (e.g. a power change scenario may be followed by an equipment failure). A classroom session of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> per year had also been recently initiated.
Several operators expressed a positive opinion of the special value of the classroom session on the technical basis for the E0Ps. There was no regularly scheduled, structured, on-the-job training for the E0Ps. The level of training as expressed by the operators and as observed by one crew's performance on the simulator was high. Ai
,mented level of on-the-job trairring would support both the validation and the continued maintenance of the E0Ps, discussed in Section 3.1.5.
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(5) Cerununication - All personnel interviewed identified the need for effec-tive eno reliable communications within the control room.
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training and maintenance of the same shift crew membership was the approach used by the licensee towards achieving this goal.
Communication between local stations and with the control room was an area of concern among the operators. Methods for using two-way radios had been implemented as a backup to the plant paging system which was a single unit for both paging and telephones.
(6) Control Room Environment - The operators indicated that the control room lighting under emergency lighting was checked periodically during refueling outages.
In addition, emergency lighting conditions were
' reproducible in the training simulator and were demonstrated to the inspection team. A Halon System was used for fire protection in the control room which was non-damaging to electronic equipment and relatively non-toxic.
Evacuation of the control room and implementation of the remote shutdown panel was the anticipated response to initiation of the Halon System.
(7) Balance of Plant / Local Control Stations - Many of the personnel inter-
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viewed indicated that the validity of the E0P directions involving local stations would be benefited by a walk-chrough of those portions of the procedures referenced by the E0Ps. This observation illustrated the need for an adequate validation program identified in Section 3.1.1.
Improve-ments in labelling, availability and storage of temporary equipment and specificity of the E0P information were also desired.
(8) Verification and Validation - Control room operators at the SS and SCO level participated in the initial development of the E0Ps.
The actual writing of the E0Ps was performed by two shift supervisors.
The initial validation of the E0Ps was performed on the Dresden simulator by control room operators as part of the initial training on the E0Ps.
The operators indicated that additional validation in the MNPS-1 plant would identify discrepancies particularly at the local stations.
The interviews also indicated that a structured program for continued validation and upgrade of the E0Ps did not exist, but that the operators were aware of their responsibility to initiate interim change requests for identified discrepancies.
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3.6 Containment Venting Provisions The team reviewed the EPGs and the Appendix C, Calculation Procedure No. 14
"Primary Containment Pressure Limits," to, determine if the PSTG values were computed correctly.
The team also reviewdd the method, flow path, and feasibility of the containment venting procedure.
E0P 580, "Containment Control " steps 3.2.9 and 3.2.2 required venting the containment in accordance with OP 311. "Containment System," at 2 psig and approximately 65 psig, respectively. Contaiment venting was clearly implemented without further direction after the accident mitigation strategies had failed and was accomplished irrespective of the radiological release.
OP 311 step 7.7 specified a filtered vent path for use as directed by 4he E0Ps.
This path was a 2-inch hard pipe bypass of either the drywell or suppression chamber isolation valves through the Standby Gas Treatment System (SBGT) to the plant vent stack. The path from the suppression chamber was through valves A0V-23-
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1-AC-12 and A0V 1-AC-10 to the SBGT and stack. The path from the drywell was throuch valves A0V 1-AC-9 and A0V 1-AC-10 to the SBGT and stack.
Valves A0V 1-AC-9 and A0V 1-AC-12 were 2 inch valves and A0V 1-AC-10 was a 12 inch valve.
The SBGT trains were tested at 1 psig and had a working pressure of a.5 psig.
Plant drawings indicated the availability of other containment vent paths, however these paths had not been evaluated or included in OP 311. The licensee had not performed an engineering evaluation to demonstrate that the containn.ent vent paths had the capacity to pass sufficient flow under the anticipated accident conditions or to demonstrate that the piping and valves would properly function with the postulated flows, pressures and tenperatures.
In addition, an evaluation was not performed to support the use of the SBGT system under the postulated accident conditions.
As discussed in Section 3.2.1, the venting of the containment was perfonned at the Primary Containment Design Pressure Limit and not at the higher Primary Containment Pressure Limit required by the BWROG EPGs.
In addition, the calculation of this pressure limit was performed incorrectly due to the use of the suppression chamber pressure instrument with an instrument tap located at 22.2 feet vice the pressure instrument with an instrument tap height of 2.2 feet.
The net effect of this error was that at containment water levels above 13.5 feet containment venting would be initiated approximately 6 psig lower than actually required.
The inspection team also determined that there were no provisions to manually operate the 12 inch vent valves at the local station. Manual operation of these valvcs would be required in the event of a station blackout because the air operated valves did not have air accumulators and would fail shut on loss of power.
The inspection team concluded based upon the lack of engineering evaluations to l
support the use of the designated containment vent path, the lack of provisions to manually operate the required vent valves, and the errors in the calculation of the pressure limits, that venting of the primary containment may not be effective in niitigating the primary containment pressure increases.
4.0 MANAGEMENT EXIT MEETING The inspection team conducted an exit meeting on June 30, 1988, with licensee management and identifed the inspection findings and provided the licensee with an opportunity to question the observations. The scope of the inspection was discussed and the licensee was informed of the conclusions identified in the course of the inspection. Mr. Jim Konklin, Section Chief, Special Inspection
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Branch, hRR, and Mr. Ebe McCabe, Section Chief, Division of Reactor Projects, i
Region I, represented NRC management at the final exit meeting.
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APPENDIX A Personnel Contacted
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A large number of personnel were contacted during the inspection. The following is a list of the licensee personnel involved:
- S. Scace Millstone Superintendent
- J. Stetz, Unit 1 Superintendent
- R. Palmieri, Unit 1 Operations Superintendent
- R. Kramer, Shift Supervisor
- P. Przekop, I&C Supervisor
- R. Lueneburg, Operator Training Supervisor
- P. Blasioli, Licensing Supervisor
- J. Barnet, Licensing Engineer
- A. Stave. Human Factors Engineer
- N. Jain, Engineering
- J. LaWare, Senior Engineering Technologist D. Chatfield, Con'.rol Operator R. Kennedy, Contro' Operator C. Shimckus, Control Operator D. Schmidtknecht Shift Supervisor D. Late, Supervising Control Operator B. Adams, Control Operator D. Lamoreaux, Control Operator M. Cassidy, Shift Supervisor Staff Assistent G. Giles, Senior Instructor C. Tabone, Senior Instructor D. Meekhoff, Senior Instructor
- Denotes those present at the Exit Meeting on June 30, 1988.
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O APPENDIX B Documents Reviewed
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ACP 3.02, "Station Procedures and Forms," Revision 43 ACP 3.10. "Preparation, Review and Disposition of Plant Design Change Records," Revision 2 ACP 6.01, "Control Room Procedure," Revision 18 ACP 6.12. "Shift Relief Procedure," Revision 2
, Calculation C3, "Suppression Pool Heat Capacity Temperature Limit" Calculation C5, "Cold Shutdown Boron Weight" Calculation C8, "Maximum Drywell Spray Flow Rate Limit" Calculation C9, "Drywell Spraj Initiation Pressure Limit" Calculation Cll, "Suppression Chamber Spray Initiation Pressure" Calculation C12. "Pressure Suppression Pressure Limit" Calculation C13. "Primary Containment Design Pressure" Calculation C17, "Minimum Number of SRVs Required for Emergency Depressurization" Calculation C18 "Minimum SRV Reopening Pressure" Calculation C24. "Hot Shutdown Boron Weight" E0P 569, "E0P Administrative Procedure," Revision 1, Change 1 E0P 570, "RPV Level Control," Revision 3. Change 0 E0P 571, "RPV Pressure Control," Revision 2, Change 1 E0P 572, "RPV Power Control," Revision 2. Change 3 E0P 573, "RPV Spray Cooling," Revision 2, Change O E0P 574, "RPV Steam Cooling," Revision 2 Change 1 E0P 575, "RPV Level /Rx Power Control," Revision 2. Change 1 E0P 576, "RPV Level Resoration," Revision 1 Change 1 E0P 577, "Emergency RPV Depressurization " Revision 1, Change O E0P 578, "RPV Flooding," Revision 1. Change 1 E0P 579, "Alternate Shutdown Cooling," Revision 1, Change 1 E0P 580, "Containment Control," Revision 2, Change 0 ONP 503C, "Station Blackout," Revision 2
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ONP 509, "Excessive Radiation Levels," Revision 1 ONP 516. "High Energy Pipe Rupture," Revision 1 OP 261, "Control of Operator Aids," Revision 2 OP 302, "Control Rod Drive System," Revision 17
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OP 303, "Reactor Cleanup System," Revision 16 OP 304, "Standby Liquid Control System," Revision 14 OP 306, "Reactor Vessel Head Cooling System," Revision 10 OP 317. "Main Steam System," Revision 10 OP 335. "LPCI Containment Cooling System," Revision 15 1-0PS-1.09, "Conduct of Operation," Revision 1 1-0PS-2.01, "Shift Assignments and Schedule," Revision 24
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