ML20214N040
| ML20214N040 | |
| Person / Time | |
|---|---|
| Issue date: | 03/24/1986 |
| From: | Stello V NRC OFFICE OF THE EXECUTIVE DIRECTOR FOR OPERATIONS (EDO) |
| To: | |
| Shared Package | |
| ML20214N035 | List: |
| References | |
| FOIA-86-496, REF-GTECI-A-03, REF-GTECI-A-04, REF-GTECI-A-05, REF-GTECI-SG, RTR-NUREG-0844, TASK-A-03, TASK-A-04, TASK-A-05, TASK-OR, TASK-PII, TASK-SE GL-85-02, SECY-86-097, NUDOCS 8609160048 | |
| Download: ML20214N040 (8) | |
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POLICY ISSUE.
SECY-86-9h March 24,1986
(
(information)
FOR:
The Comissioners FROM:
Victor Stello, Jr.
Acting Executive Director for Operations
SUBJECT:
STEAM GENERATOR USI PROGRAM - UTILITY RESPONSES TO STAFF RECOMMENDATIONS IN GENERIC LETTER 85-02 PURPOSE:
To inform the Comission of utility responses to staff I
recommendations stemming from steam generator, Unresolved Safety Issues (USIs) A-3, A-4, and A-5.
BACKGROUND:
NRC Generic Letter 85-02 was issued on April 17, 1985, to inform licensees and applicants of PWRs and Fort St. Vrain of steff recomended actions 'steming from the staff's program I
for the resolution of USIs A-3, A-4, and A-5 regarding steam generator tube integrity. This letter also requested that the subject licensees and applicants provide a description of their overall programs for assuring steam generator tube integrity and for steam generator tube rupture mitigation.
The description of the plant-specific programs was requested to be of sufficient detail to permit the staff to compare these programs with the staff recomended actions.
This paper responds to Comission directives transmitted from the Secretary to the Executive Director for Operations in a January 23, 1985 memorandum for a sumary report on the number and qualitf of responses received from utilities in response to the staff recomended actions. This paper also provides the staff's assessment of these responses and planned follow-up efforts.
CONTACT:
G. Holahan, ORAS/NRR x24410 8609160048 860911 PDR FOIA WILLIAM 86-496 PDR
The Commissioners
- DISCUSSION:
Number and Quality of Responses 1
Utility responses to the staff recomended actions.have been 3
received for all PWRs with the exception of plants where constructi'on has been delayed indefinitely. The applicants for Washington Nuclear 1 and 3 and Midland 1 and 2 have committed to submitting responses when and if construction is resumed.
A response was also submitted for the steam generators at the Fort St. Vrain gas-cooled reactor plant.
Overall, the staff believes the quality of the responses was adequate to meet the objectives of the information gathering i
effort; namely to gather data regarding how licensee programs 4
and practices in certain key areas compare to the staff recommended actions in terms of the effectiveness of these approaches in ensuring steam generator tube integrity and the mitigability of steam generator tube ruptures. Where necessary, additional infomation concerning the licensee programs was l-obtained by telephone. This data has permitted the staff to observe the industry-wide trends in the licensee programs in these areas and the variability in these programs among; plants.
Considering that the licensee responses were submitted on a voluntary basis, the overall industry response to the staff's request for information must be considered good. However, caution must be exercised in drawing long range conclusions from this information since many aspects of licensee responses in areas addressed by the staff recommended actions go beyond current regulatory requirements. Licensees have not formally comitted to continue implementation of these aspects in the future.
Also, implementing procedures, where applicable, were not reviewed by the staff.
Assessment of Utility Responses to Staff-Recommended Actions in Generic Letter 85-02 The utility responses to NRC Generic Letter 85-02 relative to each of the staff recommended actions were reviewed by the cognizant staff technical review branch for that particular issue. Where differences existed between a staff recommended action and a utility's approach (i.e., program, practice, or policy) to the area of concern addressed by the staff's recommendation, the staff evaluated the effectiveness of the utility's approach in ensuring steam generator tube integrity and/or mitigability of steam generator tube ruptures as compared to the specific actions recommended by the staff. For each plant, I
the licensee's approach to each area of concern was ranked by the staff as being largely consistent or equivalent; partially
4 The Commissioners 1 consistent or equivalent; or not consistent or equivalent to the staff recommended actions.
It must be emphasized at this
~
point that these rankings are intended only for purposes of comparison with the staff recommended actions. These rankings do not necessarily translate to adequate, partially adequate, or inadequate.
Table 1 provides an overall summary of the number of plants falling into each of the above three categories for each issue L
addressed by the staff's recommended actions.
It can be seen in this table that with the exception of condenser inspection programs, the large majority of licensees and applicants are following programs, practices, and/or procedures which appear to be largely consistent with or equivalent to the staff i
recommended actions.
In addition, few licensees are'following approaches which are not at least partially consistent with or equivalent to the staff recommended actions.
Of particular interest in Table 1 are the industry responses to the issues dealing with the prevention and detection of loose parts (issues 1.a and 1.b), and secondary water chemistry control (issue 4). Actions pertaining to these issues have been shown in the staff's value-impact analysis to have the greatest potential for reducing the frequency of steam generator tube rupture events and the associated potential for significant non-core melt levels l
of radiological releases.
In addition, actions pertaining to secondary water chemistry control have been shown to have the highest potential for producing significant reductions in occupa-tion radiological exposures.
Except as noted for three plants in Table 1, all plants appear to be implementing actions and programs concerning these issues which appear to be at least partially consistent with or equivalent to the staff's recommended actions, with the large majority of plants implementing programs which appear to be largely consistent or equivalent to the staff recommendations.
The utility responses with respect to the condenser inspection issue merit discussion since most utility practices in this area either fall short of or did not fully address the staff recommended actions. The staff believes that implementation of the staff recommended actions in this area will be beneficial in ensuring the leak tightness of the condensers as part of a successful secondary water chemistry program. However, regardless of the actual utility approach to condenser inspections, the key to a P
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The Commissioners.
successful water chemistry program will be the commitment of plant management to maintaining the water chemistry.to within the program specifications and taking tin.ely corrective action, including reductions and plant shutdowns as appropriate, for out-of-specification conditions. Thus, a comitment by plant i
management.to a successful secondary water chemistry program, plus the desirability from an economic standpoint of minimizing power reductions and plant shutdowns provides strong incentive for i
implementing adequate condenser maintenance.
Another poin+ of particular interest in Table 1 concerns the l
Technical.* ~ ification limits on primary to secondary leakage at Oconee h m 2 and 3.
Because secondary water chemistry and
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steam gene w tube inspection programs have not been successful in totally t
~ ting primary to secondary leakage, Technical Specification ;L on allowable primary to secondary leakage have been reitec son to ensure that the plant will be shutdown for appropriate corrective action before an SGTR occurs. With the exception of Ocoree Units 2 and 3, Technical Specification leakage limits for an individual steam generator generally range among plants from 0.1 gallons per minute (gpm) to 1.0 gpm.
(The staff recommended limit is about 0.35 gpm per steam generator).
The plant Technical Specification limit for Oconee Units 2 and 3 is 10.0 gpm which the staff does not consider to be a sufficiently effective limit for proventing tube ruptures. Although the licensee, in practice, has normally initiated a plant shutdown when the measured leak rate reaches 0.3 to 0.5 gpm, the staff has initiated discussions with the licensee for changes to the plant 4
Technical Specifications to incorporate an acceptable limit.
None of the staff's findings in Table'1 are indicative, in-and-of-themselves, of significant risk, and with the exception of primary to secondary leak rate limits for Oconee Units 2 and 3, none are indicative of areas requiring formal regulatory action at this time. The staff's findings, however, are indicative of areas where the effectiveness of overall plant-specific programs can be improved. The staff will inform licensees of its findings i
relative to their plants and will continue to encourage utilities to implement the staff's recomendations or appropriate alter-natives.
As has been previously reported to the Comission, the staff has concluded that steam generator tube rupture events are not a major contributor to overall risk from nuclear power plants.
Industry trends toward implementation of more effective preventive maintenance programs will serve to counteract the effects of increasing age and attendant accumulated mechanical and corrosion-induced degradation of the steam generators, and thus will provide added assurance that risk will continue to be small.
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P The Commissioners.
. However, it is important to recognize -that SGTR events are not an inherent " low risk" issue. Rather, low risk is' ' assured only through implementation of programs which are effective in ensuring steam generator tube integrity and SGTR mitigability. As has been true $n the past, utilities must be vigilant against new or unusual', problems which may necessitate preventive, diagnostic, and/or corrective actions beyond normal utility practices and/or regulatory requirements. The staff will continue to' monitor steam generator operating experiences as an indicator of the effectiveness of utility programs. Again, as has been the case in the past, the staff may require additional actions on a plant-specific basis in cases of severe or extensive degradation where such actions are needed to provide continued assurance of low risk and compliance with the regulations. Any such requirements would of course, be subject to the Commission's backfit rule as applicable.
SUMMARY
AND CONCLUSIONS:
1.
Licensees and applicants for all PWRs and Fort St. Vrcin provided responses to the staff recommended actions.
The quality of the responses were generally adequate to meet the objectives of the information-gathering,
effort.
2.
The responses indicate that the large majority of the licensees and applicants are following programs, practices, and/or procedures which are partially to fully consistent or equivalent to the staff recommended actions.
It appears that both industry initiative and the staff recommendations have been responsible for significant improvements over the past few years.
3.
The staff will continue to monitor operating experience.
As in the past, the staff may require additional actions on a plant-specific basis in instances of severe or extensive degradation as needed to ensure continued safe operation of the plant. Such requirements would be subject to the Commission's backfit rule where applicable.
. - ~ -
The Comissioners 4.
Changes to the Technical Specification limits. 'on primary-to secondary leakage for Oconee Units 2 and 3 are necessary to ensure that appropriate corrective actions are taken before rupture occurs. The staff is currently discussing the needed changes with the licensee.
5.
The staff will issue its findings regarding the individual utility responses to NRC Generic Letter 85-02 to the respective utilities. Licensees will be encouraged to upgrade their program as needed to meet the intent of the staff's recommended actions; however, this will not be a requirement.
6.
The staff recommended actions will be used as review guidance for OL applicants; however, applicants would be required to make programmatic changes only where these changes are found to be consistent with the Comission's backfit rule.
In order to ensure consistency among staff guidance documents in these areas, the Standard Review Plan and Standard Technical Specifications will be revised as necessary to be consistent with the Staff recommended actions.
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7.
The staff's program document for resolving USI's A-3, A-4, and A-5 is being updated to reflect the staff's findings from the infonnation-gathering effort herein.
This document, NUREG-0844, was issued in draft form for public coment in April 1985 and is scheduled for final publication in April 1986.
Final publication for NUREG-0844 will constitute final resolution of USI's A-3, A-4, and A-5 regarding steam generator tube integrity.
l.
/
C Victor Stello, Jr.
Acting Executive Director for Operations l
Enclosure:
l Table 1 i
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ENCLOSURE TABLE 1 NUMBER OF PLANTS WHICH ARE CONSISTENT, PARTIALLY CONSISTENT, OR NOT CONSISTENT OR EQUIVALENT TO STAFF REC 0f9 TENDED ACTIONS Largely Consistent Partially Consistent Not Consistent Issu7 or Equivalent or Equivalent or Equivalent Remarks Loos 2 Parts 55 22 2*.
' dArkansas 1 Visual Inspection Crystal River Note 1 Improved QA 56 21 0
Notes 1 and 2 Full Lcngth Tube Inspection 60 18 1*
- Vogtle Note 1 Maximum Inspection Interval 62 3
12*
- Haddam Neck, Vogtle, i
Wolf Creek, Callaway, South Texas 1/2, Bryon 1/2, Braidwood 1/2, Seabrook 1/2 Notes 1 and 2 Secondary Water Chemistry 69 10 1*
- Indid?oint3 P
Note 3 m
Cond:nser ISI Program 29 45 3*
- Farley 1/2, Indian Point 3 Note 2
Largely Consistent Partially Consistent Not Consistent Issu7 or Equivalent or Equivalent or Equivalent Remarks Primary to Secondary Leakage 60 18 2*
8*
- Haddam Neck, Indian Point 2, Kewaunee;
'"Oconee 1/2/3; i
Rancho Seco; Arkansas 1 Note 1 20% of STS 1
0 1*
- Indian Point 2 Note 4 l Safety Injection Reset 10 0
0 Note 5 NOTES:
1.
Not applicable to Fort St. Vrain 2.
Procedures under development or review for 2 NTOL plants.
3.
A secondary water chemistry program consistent with Staff's recommendation will be implemented for Indian Point 3 in 1986 following necessary plant modification.
4 Not applicable for 78 plants.
5.
Nst applicable for 70 plants.
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- parug'o UNITED STATES 8
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NUCLEAR REGULATORY COMMISSION o
.p WASHINGTON, D. C. 20555
/
JAN 21 1986 Docket No. 50-285 Cmaha Public Pcwer District ATTN:
Bernard W. Reznicek President and Chief Executive Officer 1623 Harney Street Omaha, Nebraska 68102 Gentlemen:
SUBJECT:
SAFETY SYSTEMS OUTAGE MODIFICATION INSPECTION (DESIGN) 50-285/85-22 This letter conveys the results and conclusions of the design portion of the Fort Calhoun Station Safety Systems Outage Modification Inspection conducted by the NRC's Office of Inspection and Enforcement.
The inspection team was composed of personnel from the NRC's Office of In:pection and Enforcement and consultants.
The inspection took place at the Fort Calhoun Station and at your offices in Omaha, Nebraska.
This inspection was part of a trial NRC program being implemented to examine the adequacy of licensee management and control of modifications performed during major plant outages.
The purpose of this portion of the Safety Systems Outage Modification Inspection Program was to examine, on a sampling basis, the detailed design and engineering which was required to support the outage.
Coordination with teams conducting other portions of the inspection, including vendor inspections, installation inspection, and the preoperations inspection, was required.
At the conclusion of these inspections the NRC will provide a report summarizing these efforts.
The items identified by the team during the inspection have been classified as deficiencies, unresolved items, and observations.
Deficiencies regarding errors, procedural violations and inconsistencies are identified in the report.
Unresolved items are identified where more information is needed to reach conclusions.
Other observations are identified where it was considered appropriate to call your attention to matters which are not deficiencies or unresolved items, but which are recommended for your consideration.
Chapter 1 of the report provides a summary of the results of the inspection and the conclusions reached by the inspection team.
There appear to be several significant weaknesses which were identified in your design control processes. One of these was your failure to obtain, maintain and use design basis information to assure that the original design margins are not unintentionally abrogated. We are also concerned that post-modification testing procedures were inadequate to confirm that the physical modifications fulfill the functional design requirements of the system or component.
Several problems relating to your performance of safety evaluations required by 10 CFR 50.59 and handling of emergency modifications were also identified.
One finding identified that you had failed to modify a support and edequately analyze a
[L(k 14 h
Omaha Public Power District piping subsystem in the auxiliary feedwater system in accordance with your specific commitments to the NRC.
During the installation portion of this inspection, the NRC performed a preliminary review of your planned corrective actions for the significant findings which were identified at the interim status briefing on October 8, 1985.
These included both short term actions to be completed prior to return to operation and long term corrective actions.
A more detailed review of your corrective actions, both long term and short term, will be conducted after the 60 day period allowed for your response to this inspection report.
You should respond in writing to the deficiencies and unresolved items within 60 days after receipt of this letter.
In your assessment of individual deficienc.ies identified in the inspection report, you are requested to address the cause, the extent to which the condition may be reflected in the unreviewed portion of the design, action to correct the existing coadition, action to prevent recurrence, and any other information you consider relevant.
For unresolved items, the response should provide information needed to reach conclusions concerning accept-ability of the specific feature or practice involved.
Comments on observations may be included in your response.
Several of the items identified by the team may be considered Potential Enforcement Findings.
Formal enforcement actions, including any further actions required, will be identified subsequent to the 60 day period allowed for your response.
These will be included in the summary report of the trial outage inspection.
In accordance with 10 CFR 2.790(a), a copy of this letter and the enclosures will be placed in the NRC Public Document Room.
Should you have any questions concerning this inspection, please contact me or Mr. Ralph Architzel (301-492-8852)of this office.
Sincerely,
/
\\
%TV J mes M. Taylo Director l
ffice of Inspection and Enforcement i
Enclosure:
Inspection Report 50-285/85-22 i
cc w/ enclosures:
See next page l
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=
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Mr. B. W. Reznicek Fort Calhoun Station Omaha Public Power District Unit No. I cc:
Harry H. Voigt Esq.
LeBoeuf, Lamb, Leiby & MecRae 1333 New Hampshire Avenue, NW Washington, D.C.
20036 Mr. Jack Jensen, Chaiman Washington County Board of Supervisors Blair, Nebraska 68023 Metropolitan Planning Agency ATTN: Dagnia Prieditis 7000 West Center Road Omaha, Nebraska 68107 Mr. Phillip Harrell, Resident Inspector U.S. Nuclear Regulatory Comission P. O. Box 309 Fort Calhoun, Nebraska 68023 Mr. Charles B. Brinkman, Manager Washington Nuclear Operatins C-E Power Systems 7910 Woodmont Avenue Bethesda, Maryland 20814 Regional Administrator, Region IV I
U.S. Nuclear Regulatory Comission Office of Executive Director for Operations 611 Ryan Plaza Drive, Suite 1000 Arlington, Texas 76011 Mr. William C. Jones Vice President, Nuclear Production, Production Operations, Fuels, and Quality Assurance and Regulatory Affairs Omaha Public Power District 1623 Harney Street Omaha, Nebraska 68102
U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Division of Quality Assurance, Vendor, and Technical Training Center Programs Report No.:
50-285/85-22 Docket No.:
50-285 Licensee:
Omaha Public Power District 1623 Harney Street Omaha, Nebraska 68102 Facility Name:
Fort Calhoun Station Inspection At:
Omaha Public Power District Engineering Offices, Omaha, Nebraska Fort Calhoun Station, Blair, Nebraska Inspection Conducted:
September 16-20, 30, and October 1-8, 1985 Inspection Team Members:
Team Leader:
R. E. Architzel, Senior Inspection Spec,ialist, IE Mechanical Systems:
G. J. Overbeck, Consultant, Westec Services Mechanical Components:
A. V. duBouchet, Consulting Engineer Electrical Power:
G. W. Morris, Consultant, Westec Services Instrumentation &
Control:
L. Stanley, Consultant, Zytor Inc.
Design Control:
A. Saunders, Reactor Engineer, IE*
M. Murphy, Reactor Inspector, Region IV*
R. Lloyd, Reactor Engineer, IE*
/
// /2// ? lf?S Ralph E. A'chitzel
' Date Team Leader w [.
1 L /a//J/gf Approved by:
\\
i ames L. Milhoan Date (Lection Chief Nuality Assurance Branch
- Part time Q.
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LIST OF ABBREVIATIONS ACI American Concrete Institute AISC American Institute of Steel Construction ASME American Society of Mechanical Engineers ANSI Amerian National Standards Institute ASTM American Society for Testing and Materials CFR Code of Federal Regulations ESF Engineered Safety Features FSAR Final Safety Analysis Report GSE Generation Station Engineering HVAC Heating, Ventilation and Air Conditioning IEEE Institute of Electrical and Electronics Engineers LOCA Loss of Coolant Accident MR Modification Request NRC U.S. Nuclear Regulatory Commission NSSS Nuclear Steam Supply System OPPD Omaha Public Power District OSAR Operations Support Analysis Report P&ID Piping and Instrumentation Diagram USAR Updated Safety Analysis Report
1.
INTRODUCTION AND
SUMMARY
1.1 INTRODUCTION
The following subparagraphs provide introduction to the objectives, format and focus of the Fort Calhoun Safety Systems Outage Modification Inspection.
1.1.1 OBJECTIVES This inspection was part of a trial NRC program being implemented to examine the adequacy of licensee management and control of modifications performed during major plant outages.
The purpose of this portion of the Safety System Outage Modification Inspection Program was to examine, on a sampling basis, the detailed design and engineerirg which was required to support the outage.
1.1.2 REPORT FORMAT AND DEFINITIONS The areas examined during this inspection are addressed by discipline in the following chapters.
Deficiencies, unresolved items, and observations are defined below and are included in an appendix to this report.
(1) Deficiencies Errors, inconsistencies or procedure violations with regard to a specific licensing commitment, specification, procedure, code or regulation are described as deficiencies.
Follow-up action is required for licensee resolution.
(2) Unresolved Items Unresolved items are potential deficiencies which require more information to reach a conclusian.
Follow-up action is required for licensee resolution.
(3) Observations Observations represent cases where it is considered appropriate to call attention to matters that are not deficiencies or unresolved items. They include items recommended for licensee consideration but for which there is no specific regulatory requirement.
No licensee response is required.
1.1. 3 FT. CALHOUN PROJECT ORGANIZATION The Omaha Public Power District is the licensee for the Ft. Calhoun Nuclear Power Plant.
As such, Omaha Public Power District is responsible for the design, construction and operation of the facility.
The utility holds responsibility for the overall plant design, with contract design support from Stone and Webster.
The original architect / engineer (Gibbs and Hill, Durham and Richardson) is no longer under contract to the licensee. Other firms are occasionally engaged for services.
Combustion Engineering designs and provides the nuclear steam supply system.
The nuclear steam supply contract is managed directly by Omaha Public Power District.
1
1.1.4 INSPECTION EFFORT The inspection was an interoffice NRC effort conducted with contractor assistance.
Team members were selected to provide technical expertise and design experience in the disciplines listed.
Most of the team members had previous experience as employees of architect-engineering firms or reactor manufacturers working on large commercial nuclear power plants.
The others had related design experience on commercial nuclear facilities, test reactors, or naval reactors.
Beginning on August 12, 1985, a portion of the inspection team devoted one week to the initial study of background information and preparation of plans for the inspection.
The week of August 19, 1985 was spent at the site and at the licensee's office to become familiar with the respective organizations and interfaces and to gather additional background material.
The majority of the team inspection activities occurred at the Generating Station Engineering Offices, Omaha, Nebraska, the weeks of September 16 and September 30, 1985. The inspection activities concluded on October 8, 1985 with an Interim Status Briefing.
The inspection team reviewed the organizations' staffing and procedures and interviewed personnel to determine the responsibilities of and the relationships among the entities involved in the design process.
Primary emphasis was placed upon reviewing the adequacy of design details (or products) as a means of measuring how well the design process had functioned in the selected sampling area.
In reviewing the design details, the team focused on the following items:
(1) Validity of design inputs and assumptions (2) Validity of design specifications (3) Validity of analyses (4) Identification of system interface requirements (5) Potential indirect effects of changes (6) Proper component classification (7) Revision control (8) Application of design information transferred between organizations (9) Design. verification methods l
The team inspected four engineering disciplines within the project.
The four disciplines were mechanical systems (Section 2), mechanical components (Section 3), instrumentation and controls (Section 4), and electric power (Section 5).
- 1. 2
SUMMARY
- MECHANICAL SYSTEMS The team re/iewed two modification packages in detail and two additional modification packages in part.
The packages reviewed included modifications planned for the current outage and completed modifications.
i The team identified a number of examples of deficient design activity.
Based
(
on the modification packages reviewed, these items can be categorized as l
follows:
2 i
(1) In certain instances, engineering input into post-modification testing procedures was inadequate to confirm that physical modifications fulfill tne functional design requirements of the system or component l
(Deficiency D2.1-7 and D2.2-3).
(2) Seismic requirements were not properly addressed in modification packages (Deficiency D2.2-3 and Observation 02.1-5).
(3) In certain instances, errors found in the design details indicate that design verifications were not performed in sufficient detail to substantiate the design.
In addition, the design verification process was normally performed prior to site acceptance (following construction and testing of the modification) rather than as the design output.
documents were completed.
This practice, can needlessly place the t
independent reviewer in a time critical role for plant restart.
(Deficiencies D2.1-6, D2.1-7, D2.2-1, D2.2-2, D2.2-3, and D2.2-6).
(4) Incorrect or inappropriate documents were being used as sources of design input with insufficient consideration given to the original plant design basis (Deficiencies 02.2-1 and D2.2-6).
The team noted that Omaha Public Power District engineers expressed different opinions as to the appropriate source documents for design input.
Generating Station Engineering personnel indicated that controlled copies of system i
descriptions are sources of design input and design criteria, but the operations staff associated with the upkeep of the system descriptions informed the team that the system descriptions are for operational use and that the USAR is the source of design input and criteria.
The team identified a weakness in the design control process in that original design bases and 4
i calculations have not been maintained in a workable form and subsequent modifications have not been maintained as auditable design input documents.
This condition is aggravated because design calculations are not maintained as living documents.
Instead design calculations are prepared and filed with the a
modification package at the discretion of the design engineer.
As a consequence, existing design calculations covering certain design attributes are not readily retrievable or may not exist.
This may result in a lack of design traceability from design input through to design output and an inability t'o determine the design bases of systems and components.
i The team found that engineering judgments were frequently not documented when l
used as the basis for not performing a calculation. The lack of this docu-i mentation, including appropriate justification, results in the lack of a '.jasis for design verification and the lack of a traceable and auditable path from design input to design output.
Omaha Public Power District procedures do not address the use of engineering judgment and the team has found excessive reliance on its use.
This is considered to be a significant weakness.
- 1. 3
SUMMARY
- MECHANICAL COMPONENTS The team performed a design review of selected modifications to piping systems and equipment at Fort Calhoun Station.
The team additionally reviewed l
installed piping and equipment identified during a visit to Fort Calhoun l
Station on September 20, 1985.
The team also reviewed the design basis for l
balance of plant piping systems and equipment at Fort Calhoun Station.
3 1
l
Omaha Public Power District appears unable to access the design specifications originally prepared by Gibbs, Hill, Durham and Richardson for Fort Calhoun Station, and has not prepared alternate controlled design documentation for use by Omaha Public Power District design personnel.
(Deficiency D3.1-1).
In preparing the piping design for plant modifications, Omaha Public Power District has not referred to the operating and accident temperatures and pressures originally used by the architect-engineer to analyze Safety Class 1 large-bore pipe, nor did Omaha Public Power District prepare alternate controlled pressure and temperature data for use by Omaha Public Power District design personnel in lieu of retrieving the original design basis.
(Deficiency D3.1-2).
The team identified a possible discrepancy between the generic spacing criteria which the contractor, Peter Kiewit, used to install small-bore pipe during initial construction and the minimum horizontal frequency criterion specified in USAR Appendix F for small-bore i
pipe penerating or connected to the containment shell.
(Unresolved Item U3.1-3).
The team found that none of the six modification packages reviewed adequately i
documented the design basis for the installed piping and equipment.
The team also found that none of the six modification packages reviewed adequately qualified the revised piping and equipment configuration by analysis, particularly with respect to the Class 1 seismic criteria detailed in USAR Appendix F.
In addition, Omaha Public Power District was not able to produce the seismic qualification of the junction box /unistrut support configuration which the team I
identified during a visit to the site on September 20, 1985.. Of particular concern to the team are the numerous deficiencies identified in Omaha Public Power District modification request FC-81-127.
Omaha Public Power District performed this modification in response to NRC Generic Letter No. 81-14.
This modification forms the basis for ensuring that the auxiliary feedwater system will function following the occurrence of earthquakes up to and including the safe shut-down earthquake for Fort Calhoun Station.
The team noted that a specific licensee I
commitment to modify an unstable valve operator prior to the end of 1981 had been j
made to the NRC, however the valve's support had not been modified.
1.4
SUMMARY
- INSTRUMENTATION AND CONTROL In the instrumentation and control area, the team found that most of the design modifications were being accomplished in a controlled and technically acceptable manner. However, the individual items which were noted by the team appeared to be caused by certain common factors, such as:
(1) Insufficient consideration of the original plant design basis (Observations 04.1-1 and 04.3-3).
(2) Inadequate review of technical assumptions in the design (Observation 04.2-1, Deficiency D4.3-1 and Unresolved Items U4.3-2, U4.4-1, and U4.5-3).
(3) Procedural weaknesses related to design verification (Deficiency D4.3-1 and Observation 04.3-3).
In a number of instances noted by the team, the Omaha Public Pcwer District engineers did not indicate a sufficient asareness of the Fort Calhoun design basis
(
when design modifications were developed and completed (Observations 04.1-1 and 04.5-2 and Unresolved Item 04.4-1).
Retrievability of some des 1gn basis infor-mation appeared to be a significant obstacle, and there was evidence of a strong dependence on the Updated Safety Analysis Report for such information.
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The team noted a strong dependence on use of checklists in the design, and design verification processes. While use of checklists is necessary, this practice does not appear to be sufficient to properly consider technical assumptions made by the design engineer in the design prccess.
1.5
SUMMARY
- ELECTRICAL POWER The team reviewed three modification packages which were being prepared for the present outage.
None of these packages had been completed, having only reached the Final Design Package stage.
The Construction Package including detailed design drawings, instructions and procedures, had not yet been prepared.
The team identified problems in ir.terpretation of the USAR requirements and referenced standards (Observation 05.1-3) because of what appeared to be insufficient traceability of the existing plant to the original design basis for cable sizing.
The team identified problems in the lack of review of, or inadequate justifi-cation for acceptance of, manufacturer's data or manufacturer's computer analysis for fire protection wrapping for raceways.
(Deficiency 05.2-1)
The team identified inadequate coordination between the DC distribution breaker and the new battery charger.
(Unresolved Item U5.1-2)
The team identified inadequate checking and verification of input and assumptions used in the recent battery sizing calculation.
(Deficiency i
D5.1-1)
In general, the team found the check and verification process to be highly dependent upon the experience of the reviewer.
1.6
SUMMARY
- DESIGN CHANGE CONTROL Selected portions of the design change process were reviewed by the team.
These portions included the preparation and approval of safety evaluations, the processing of emergency modifications, and an overview of documentation of design inputs.
Several deficient conditions were identified concerning the performance of safety analyses pursuant to 10 CFR 50.59.
These include:
(1) The licensee's procedures did not require safety analysis of non-safety related changes to the facility as described in the USAR.
The team identified a number of facility changes which did not undergo 10 CFR 50.59 safety analysis (Deficiency 06.1-1).
(2) Proposed facility changes accomplished as emergency modifications were not subject to 10 CFR 50.59 safety analysis before the affected system was relied upon for facility operation (Unresolved Item U6.1-2).
In addition the team also identified several weaknesses in the licensee's process of performing safety analyses.
These include not specifically requiring a review to ascertain if technical specifications were affected 5
by changes, engineers not routinely availing themselves of NRC's position regarding the safety analysis (Safety Evaluations), and not differentiating between safety analysis required by 10 CFR 50.59 and written determinations that plant review committee review items do not constitute unreviewed safety questions (Observation 06.1-3).
The team identified a weakness regarding what the team considers excessive time to complete engineering and design work associated with emergency modifications (Observation 06.2-1).
The team also identified as a deficient condition improper design control associated with an emergency modification.
A modification to the auxiliary feedwater system was only partially completed in 1980.
The partial completion was not identified until engineering review of the modification three years later, and not corrected until the current outage.
This was not with-standing an engineering determination that the modification violated 10 CFR 50, Appendix A, General Design Criteria 57 (Deficiency D6.2-2).
Deficiencies and concerns relating to the design change process were also identified on a discipline-specific basis.
2.
MECHANICAL SYSTEMS This portion of the inspection evaluated the mechanical systems design aspects of plant modifications with emphasis on technical adequacy:
the capability of the modified system to perform all of its safety functions as prescribed by its design bases and associated safety analyses, the post-modification testing to demonstrate that the modified system will perform its safety function, traceability of the design input through to design output, and the design verification process.
The team reviewed two modifications in detail and two additional modifications in part.
Initially the inspection concentrated on planned modifications, MR-FC-83-158 and MR-FC-84-144; however, completed modifications, MR-FC-78-43 and MR-FC-81-21B, were reviewed during the latter stages of the inspection to determine if concerns developed during the review of planned outage modification package were also evident in completed modification packages.
2.1 MECHANICAL DESIGN ACTIVITY TO SUPPORT CURRENT OUTAGE The team examined summaries of the modifications planned for the 1985 outage and selected four modifications with the potential for significant engineering activity.
These four modification packages were further evaluated at Omaha Public Power District's offices to identify those packages suitable for detailed review.
A candidate modification package was or.e which altered the manner in which the system or component was operated and which required engineering calculations, drawing revisions, procurement specifications, and procedural revisions to irrplement.
Modification MR-FC-83-158 was selected for detailed review.
6
MR-FC-83-158 is a normal modification (as opposed to an emergency or minor modification; Deficiency D6.2-2 addresses the classification and handling of this modification request) to install an air accumulator on each of two valves, YCV-1045 A and B. These instrument air accumulators were to be installed to permit remote manual isolation in the event of a steam generator tube rupture with a concomitant loss of non-safety-related instrument air.
Steam is supplied to the auxiliary feedwater turbine pemp from a steam header fed by two steam branch lines, one from each steam generator.
The steam is supplied from each branch line up to downstream isolation valve YCV-1045 through normally closed isolation valves YCV-1045A and YCV-1045B in the branch lines.
These isolation valves are pneumatically operated and can be remote manually operated from the control room.
In the original system design, valves YCV-1045 A and B were designed to fail open on loss of instrument air, and valve YCV-1045 was designed to fail closed.
A modification, MR-FC-78-43, was initiated on an emergency basis in 1978 to redesign the valve operator for YCV-1045 and replace it with a fail open operator.
In addition to replacing the valve actuator of YCV-1045, air accumu-lators were to be added to the valve actuators for YCV-1045 A and B to permit the remote manual isolation of these valves from the control room in the event of a steam generator tube rupture with a concomitant loss of non-safety-related instrument air.
However, these air accumulators were not installed prior to returning the plant to power.
During close-out of MR-FC-78-43, a new engineering evaluation and assistance request was initiated and became MR-FC-83-158 to install the air accumulators. The close-out of emergency modification HR-FC-78-43 and safety evaluation which permitted plant operation are described in section 6.2 of this report and Deficiency 06.2-2.
The Final Design Description for MR-FC-83-158 states that each accumulator is to be sized to provide air to the valve actuators for one hour.
However, design calculations do not exist to confirm sizing of the air accumulators.
A calculation does not exist which demonstrates that a sufficient stored volume of pressurized air will be available to close YCV-1045 A and B assuming a loss of instrument air and minimum initial accumulator pressure.
The valve is a spring actuated to open, and sufficient air pressure must be provided to overcome spring pressure and approximately 1000 psi differential pressure across the globe valve during closure.
The team was informed that a sizing calculation was not performed for this modification package; instead the design engineer indicated that he referred to calculations in a completed modification and used engineering judgment to conclude that the current design was adequate.
The team found no documentation of the engineering judgment and requested for review the sizing calculations used by the design engineer; however, these calculations could not be found during the inspection and, therefore, were not available for review (Deficiency D2.1-1).
Appendix F of the USAR describes criteria for the seismic design of structures and components, including instruments and controls.
The Critical Quality Element List identifies those structures, systems, and components which are safety-related.
These documents form the basis for the desigr requirement that the air accumulators and associated valving and tubing be saf6ty-related and seismic designed.
Contrary to these requirements, the procurement specifications for check valves used to isolate the accumulators from the non-safety-related instrument air header, and the isolation valves used to isolate the accumlators from the valve actuator and instrument air header for maintenance, do not specify seismic requirements (Deficiency D2.1-2).
7
In addition, the team found that a vendor exception to the specification's storage requirement for the accumulator isolation valves was not reflected in the procurement document (Observation 02.1-3).
The team found no documentation in the modification file concerning the seismic and stress analyses for the air accumulators.
The team was referred to a generic calculation not applicable to a particular modification package. The team found that the control and use of generic calculations are not described in the Generating Station Engineering procedures and are the exception rather than the rule.
(Observation 02.1-5).
In examining the verification process used to confirm the final design, the team determined that MR-FC-83-158 was not treated as a normal modification in accordance with established Generating Station Engineering Procedures Manual.
This manual describes the responsibilities of personnel, the types of modification requests, the information to be included in preparation of a modification package, and steps to document field changes and close-out. The team found that a construction package was prepared even though the design verification of the final design package had not been completed.
The team noted that the actual implementation of the design verification process does not differentiate between normal and emergency modifications, although Generating Station Engineering procedures indicate that third party verifications will be accomplished as the design package for a normal modification is completed.
The team was informed that the procedures do not have this intent but rather permit design verifications to be performed prior to site acceptance.
The team was informed that Standing Order G-21 was the governing procedure; however, this order does not indicate that completion of third party verifications of a normal modification package can be delayed until site acceptance (Deficiency D2.1-6).
The team determined that post-modification testing for this change was inadequate to confirm that YCV-1045 A and B could be shut against a differential pressure of approximately 1000 psi and remain shut for one hour with the accumulator air volume alone.
The post-modification testing procedure closed the valves with no differential pressure and with instrument air header pressure instead of accumulator air pressure prior to commencing the testing.
The only acceptance criterion is that the valves must remain shut for one hour.
As a consequence, the test is a static air pressure test with no acceptance criterion provided for acceptable air leakage (Deficiency D2.1-7).
Review of USAR sections, flow diagrams, and system descriptions for various systems was performed to understand the design bases for these systems and the impact the design change had on these systems.
The team found incorrect information on the main steam system flow diagram (Deficiency D2.1-8) and in the auxiliary feedwater system description (Deficiency D2.1-9).
l 8
The most significant error was the incorrect representation of the piping arrangement associated with main steam isolation valve bypass valves and the auxiliary feedwater steam warmup lines, and as a consequence, the incorrect identification of safety class boundaries.
A safety-related portion of the system may have been considered as non-safety-related.
The team also determined that the installation package for MR-FC-83-158 did not reference a generic support spacing procedure for the installation of the instrument air lines, and did not specify the radial location of the Hilti bolts which restrain the air accumulators.
This deficiency is described in section 3.2 and Deficiency D3.2-2 of this report.
The team also examined modification MR-FC-84-144, because it was identified as a modification package the.t could be incorporated into the plant simultaneously with MR-FC-83-158.
MR-FC-84-144 is a normal modification involving the replacement of solenoid valves for YCV-1045 A and B.
The team identified no concerns with this relatively simple modification to replace a component with a like component.
However, the team noted an apparent discrepancy between MR-FC-84-144 and MR-FC-83-158 with respect to the use of fluorocarbon elastomer material.
Specifically, the design package for MR-FC-84-144 indicates that Viton, an E. I. duPont de Nemours trade name, is not recommended for application in high radiation areas and the modification is to replace the solenoids with ones which do not contain that material.
However, MR-FC-83-158 permits Viton to be used as a seating material in the safety-related applications without proper consideration of material compatibility (Unresolved Item U2.1-10).
2.2 DESIGN ACTIVITY ASSOCIATED WITH COMPLETED MODIFICATIONS The team selected modification MR-FC-81-21B for review because it is similar to modification MR-FC-83-21B, which replaced fail close pneumatic actuators with actuators that fail open.
The replacement actuators were installed on valves HCV-4388 and HCV-438D.
These valves are containment isolation valves located outside containment in the component cooling water supply and return lines associated with the reactor coolant pump lube oil coolers and seals.
Like MR-FC-81-21B, this modification added instrument air accumulators to these valves to permit the operator to maintain the valves closed until operator action could be taken to manually close the valves locally.
In addition, the modification added a component cooling water pressure low signal in series with a containment isolation actuation signal such that the presence of both signals is necessary to close the valves.
The modification file contained a calculation which used incorrect and unconservative design input to demonstrate that the air accumulator had sufficient capacity.
In the calculation, the volume of air stored in the accumulator is over estimated by 335 percent and the available air pressure is assumed to be equivalent to the maximum instrument air system pressure instead of the minimum pressure.
In addition, the calculation does not consider system l
leakage or the period of time that the valve must remain shut.
The team noted that surveillance testing is not performed to demonstrate the capability of the safety-related portion of the instrument air system to close these valves and to maintain them closed for a finite period of time without loss of function.
i I
t l
9
As a consequence, the implicit assumption of zero leakage is not conservative and realistic (Deficiency D2.2-1).
HCV-438B and D are containment isolation valves which are open following an accident and must be capable of being shut throughout the course of the accident. As a consequence, the air accumulators and associated piping and valves are seismic Class I and safety-related.
However, the team found that seismic and quality requirements were not properly addressed in the modification package.
Specifically, the team found a purchase order for seismic qualification analysis of the replacement actuator and valve assembly did not invoke the requirements of 10 CFR Part 50 Appendix B.
As a consequence, the analysis was not performed in accordance with the service organization's quality assurance program.
The team also found that the installation / test procedure did not reference a generic support spacing procedure for the installation of the instrument air tubing.
In addition, no calculation existed at the time the modification was completed to confirm that the as-constructed air accumulator, including base plate and Hilti bolts, was adequately sized to withstand expected seismic loadings (Deficiency D2.1-2).
Like the post-modification testing procedure for MR-FC-83-158, the post nodification testing procedure for MR-FC-81-21B did not require the use of the pressurized volume of the accumulator to shut the valves and only a static air pressure test was performed.
In addition, the team found no documented basis for the acceptance criterion that the valves remain shut for twenty minutes (Deficiency 02.2-3).
The team also identified information missing from modification file MR-FC-81-218.
No records of third party review were found by the team.
(Observation 02.2-4).
Portions of the compressed air and component cooling water systems were reviewed to understand the design basis and the impact the design change had on these systems.
The team found the compressed
- air system description was not updated to include valves HCV-438B and D on a list of valves equipped with instrument air accumulators.
The team noted that site acceptance of this modification indicates that the system description had been updated.
The site acceptance of this modification was completed in May 1983 and the compressed air system description was most recently revised in April 1985.
The component cooling water system description was not revised to correctly describe the change incorporated in the logic circuits to shut HCV-438B and D.
The team noted that site acceptance for this modification was completed in May 1983 and that the system description had not been updated since December 1981 (Deficiency D2.1-9).
During the team's review of the installation and test procedure, the team found two instrument air header isolation valves not depicted on an instrument air diagram showing riser details.
During a field inspection, tie team confirmed that the valves are installed in the plant (Deficiency D2.2-5).
The team also reviewed the safety evaluation included in the Final Design Description for modification MR-FC-81-218.
The team found the safety evaluation was based on an incorrect assumption and analysis methodology.
The safety analysis did not refer to original design calculations and the qualitative argument used reflects an incorrect 10
understanding of the heat transfer pheromenon between heat removal systems.
The safety analysis contains an unsubstantiated and inappropriate assumption concerning operator action to secure neat loads under certain accident conditions.
Although the basis of Technical Specification 2.4 contains incorrect information concerning the heat removal capacity of the component cooling water heat exchangers, it was not revised (Deficiency D2.2-6).
3.
MECHAIIICAL COMPONENTS This portion of the inspection evaluated selected modifications to piping systems and equipment at Fort Calhoun Station from piping analysis, piping and equipment support standpoint.
Six modification requests were included in the scope of this review.
Several issues relating to piping / equipment supports were identified during a plant tour.
3.1 Design Basis The team reviewed information relating to the design bases of Fort Calhoun Station Critical Quality Elements, Class I and II components, and their relationship to ASME classifications and other code requirements.
The team could not obtain the design specifications governing the procurement, design, fabrication and installation of the balance of plant (supplied by other than the steam supplier) piping systems and equipment for for Fort Calhoun Station that were issued by Gibbs, Hill, Durham and Richardson, the architect-engineer (A/E).
Instead of the design specifi-cations issued by the architect-engineer, Omaha Power Public District Generating Station Engineering (GSE) uses the original procurement specifi-cations which formed the basis for the design specifications issued by the architect-engineer.
However, these procurement specifications are not controlled documents (Deficiency D3.1-1).
As an example, the piping design specification of record at Fort Calhoun Station is Gibbs & Hill Piping Specifi-cation H-1, as noted in General Note 10 of the piping and instrumentation diagram symbol list.
However, Omaha Public Power District uses Technical Specification No. 1/ Piping, one of 46 design specifications contained in Omaha Public Power District Contract No. 763, Section H, which detailed the procure-ment, design, fabrication, installation and testing for much of the balance of plant piping and equipment.
The team could not obtain the operating and accident temperature and pressure data originally prepared by the architect-engineer for piping systems at Fort Calhoun Station during the inspection.
The original piping analyses performed by the architect engineer do not appear to be accessible.
In 1979, in order to perform reanalysis of large-bore safety class piping systems in response to IE Bulletin 79-14, Omaha Public Power District collated operating and accident temperatures from the FSAR and from analytical and operating data for use by Gilbert / Commonwealth.
However, Omaha Public Power District never controlled this document (Deficiency 03.1-2).
The team is concerned that Omaha Public Power District may be using this uncontrolled temperature data to perform modifications to the installed piping.
Small bore pipe was supported in accordance with the generic spacing criteria developed by the architect-engineer and detailed in Peter Kiewit (the 11
constructor) Contract 763/ Group I and Group II Piping Systems / Recommended Procedure for the Support and Seismic Restraint of Piping two Inch and Smaller.
The tabular data in this procedure details allowable pipe support spacing in the intake structure, auxiliary and containment buildings as a function of pipe diameter (1 in. to 2 in.) for small-bore piping subjected to combined dead load, thermal and seismic loads. The architect-engineer was required to provide piping thermal displacements and reactions to the contractor.
Omaha Public Power District was not able to access this information for the team.
This issue had previously been identified by the NRC Region IV office (Inspection Report 85-03).
The seismic criteria embodied in the small-bore pipe generic spacing criteria are based on minimum natural frequencies of 6 cps horizontal, 18 cps vertical, for the auxiliary building and containment.
The minimum natural frequencies specified for the auxiliary building and containment in the procedure are in agreement with the seismic criteria detailed in USAR Appendix F, Subsection F.2.2.2.
However, USAR Appendix F specified a more stringent minimum natural frequency of 12 hertz (rather than 6 hertz) horizontal for piping runs which penetrate or are connected to the containment shell, as a consequence of a slight amplification in equipment acceleration response to the normalized ground response spectra at approximately 6 hertz. Omaha Public Power District could not confirm that small-bore piping systems penetrating or connected to the containment shell are in compliance with this minimum frequency criterion (Deficiency D3.1-3).
The team also reviewed the procurement specifications for balance of plant valves with respect to the USAR Appendix F seismic criteria for Class I piping and equipment.
The Omaha Public Power District Critical Quality Element List notes that the valve specifications were developed by Omaha Public Power District and the architect-engineer, and that the valve specifications can be obtained by referring to the original contract documents.
The team examined the design specifications contained in Omaha Public Power District Contract No. 763, the original contract document used to procure the bulk of the balance of plant valves for Fort Calhoun Station.
No seismic criteria are detailed in these specifications.
Therefore, documentation is not available to establish seismic qualification of these valves.
Adequacy of equipment seismic qualification documentation, including valves and operators for older plants, has already been identified by the NRC.
This issue is being tracked for resolution as Unresolved Safety Issue A-46.
The team reviewed draft NUREG 1030, Seismic Qualification of Equipment in Operating Nuclear Power Plants, and the associated Regulatory Analysis published in the Federal Register (FR 85-21054) on September 4,1985.
The team noted that Fort Calhoun Station is one of the plants identified for NRC review pursuant to this Regulatory Analysis (Observation 03.1-4),
3.2 PIPING / EQUIPMENT REVIEW The team reviewed modification request FC-84-61, which will enable the periodic removal of safety injection relief valves S1 209, 213, 217 and 221 for setpoint testing.
The team noted that MR-FC-84-61 does not reference the source of design input used in the analysis and did not reference various applicable design bases nor document engineering judgement that such references were not needed.
(Unresolved Item U3.2-1).
12
Modification request FC-83-158, which provides air accumulators with check valves for valves YCV-1045A and B, does not reference a generic support spacing procedure for the installation of the instrument air lines, and does not specify the radial location of the Hilti bolts which restrain the air accumulators (Deficiency 03.2-2).
The team reviewed a second modification package which was similarly deficient (reference Deficiency D2.2-2).
Modification request FC-84-162 redesigns two containment ventilation duct supports to improve personnel and equipment access.
However, the Omaha Public Power District calculation does not consider Design Bases Accident thermal loads of 288 degrees F.
In addition, the revised duct support configuration, which consists of a horizontal angle and a brace, is not analyzed for the cc=bination of vertical seismic load and transverse horizontal seismic load (Deficiency D3.2-3).
During a site visit on September 20, 1985, the team identified a junction box which supplies power to the operator for valve YCV-1045B.
The junction box is restrained by a pair of unistrut supports which are in turn supported by conduit.
Omaha Public Power District could not identify a seismic analysis which qualifies this configuration to the governing seismic provisions of USAR Appendix F (Deficiency D3.2-4).
Modification request FC-83-83 replaces the containment pressure switches which feed the engineered safeguards system high containment pressure logic matrices.
The team reviewed the seismic qualification of the pressure switches and the associated switch supports and Hoffman boxes.
The Omaha Public Power District calculation performed to qualify the support for the pressure switch does not reference the vendor drawing for the pressure switch, preventing confirmation of the switch dimensions and weight used in the analysis.
In addition, the Hoffman box shown on the Omaha Public Power District arrangement drawing was not identified in the Omaha Public Power District calculation.
(Observation 03.2-5).
Modification request FC-84-92 does not adequately implement or reference the design basis for Fort Calhoun Station.
This modification contracted for the design and fabrication of nozzle dams for the hot and cold legs of the steam generator, to enable refueling to proceed concurrently with primary head work such as eddy current examinations.
The steam generator nozzle dams were designated as Critical Quality Elements (CQE) on the Omaha Public Power District nozzle dam purchase order; and were, therefore, subject to the governing Class I seismic criteria detailed in USAR Appendix F.
However, the Omaha Public Power District contract to the nozzle dam vendor, Nuclear Energy Services, did not specify any seismic provision, and Nuclear Energy Services l
did not perform a seismic analysis (Deficiency D3.2-6).
During a site tour, the team examined auxiliary feedwater steam feed valve YCV-1045B because of a planned modification to add an air accumulator to the valve's air operator supply line.
The team questioned the operator's existing support arrangement in that it was supported by a thin rod attached to a stair post and did not appear seismically qualified.
The team reviewed modification request FC-81-127, which Omaha Public Power District performed in response to NRC Generic Letter No. 81-14, Seismic Qualification of Auxiliary Feedwater Systems.
Gilbert / Commonwealth performed 13 l
l
a walkdown of the auxiliary feedwater system at Fort Calhoun Station for Omaha i
Public Power District, and identified four major seismic deficiencies, one of which involved unstable valve operator supports.
Gilbert / Commonwealth specifically noted that the valve operator for valve YCV-1045B was unstable, and i
recommended that the existing rod restraint to replaced with a strut. Gilbert /
Com m wealth recommended the addition of a number of supports for the steam drive and condensate portions of the auxiliary feedwater piping associated with pump FW-10.
Gilbert / Commonwealth also recommended that a detailed stress r
analysis of the auxiliary feedwater system be performed to confirm that the addition of restraints to the auxiliary feedwater system would not result in l
excessive thermal loads.
Omaha Public Power District Generating Station j
Engineering (GSE) elected to perform the recommended piping analysis.
The team noted the following deficient conditions relating to this analysis.
1 (1) The valve operator for valve YCV-1045B is currently restrained by a e
rod which is anchored to a stairpost fabricated from a steel angle; the strut substitution recommended by Gilbert / Commonwealth was not l
implemented; j
(2) The Omaha Public Power District as-built drawing does not detail either the valve operator or the existing valve restraint; a
i (3) The vendor drawing for valve YCV-1045B could not be accessed to i
verify the valve and operator weights, or the operator offset dimension i
used in the Omaha Public Power District piping analysis;
}
i (4) The valve operator restraint was not modeled in the Omaha Public j
Power District piping analysis; i
(5) Omaha Public Power District could not access a summary of the pipe stress due to combined dead, thermal and seismic loads in the vicinity of j
the valve; I
(6) Omaha Public Power District could not access a summary of the reactions due to combined dead, thermal and seismic loads for the supports adjacent to the valves.
Based upon cursory examination of the computer output, the supports appear to be overloaded; I
(7) The Omaha Public Power District computer runs are not referenced in I
the modification request and are therefore not auditable; and, l
l (8) As noted in Deficiency D3.2-7, the licensee specifically committed to l
correct the unstable valve operator on YCV 1045B by the end of 1981 in a July 14, 1981 letter to the NRC.
In addition, the NRC project manager i
documented a telephone conversation with the licensee, confirming completion of this action (correction of unstable valve operators), in the NRC letter forwarding the Safety Evaluation for Generic Letter 81-41, Seismic Qualification t
j of AFW Systems.
Contrary to these commitments, valve YCV-1045B and the adjacent piping and
{
supports were not adequately analyzed to the governing seismic provisions of USAR Appendix F (Deficiency 03.2-7).
i 14 l
L
4.0 INSTRUMENTATION AND CONTROL The team reviewed instrumentation and control design modification packages for:
(1) consistency with Fort Calhoun design basis requirements; (2) conformance with applicable regulatory criteria and FSAR commitments; (3) technical adequacy of the chosen design approach, and (4) completeness of design details and independent verification reviews relative to Omaha Public Power District procedures.
During the Fort Calhoun outage inspection program, the team reviewed the following fourteen instrumentation and control design modification packages:
FC-77-40, Undervoltage Protection; FC-81-64, Reactor Coolant Hot Leg Level Indication; FC-81-102, Bypass or Trip of ESF Channels Without Jumpers; FC-82-178, HEPA Filter Differential Pressure Indication; FC-83-83, Containment Pressure Switches; FC-83-109, Transfer of P250 Points to the ERF Computer; FC-84-46, High Power Rate of Change Trip Alarm; FC-84-74A, Fuse Protection for Certain Limit Switch Circuits; FC-84-96, Replacement of Safety-Related HFA Relays; FC-84-140, Delta Temperature Power Process Loops; FC-84-152, Thermal Margin / Low Pressure Trip Drawer Modification; FC-84-179, Addition of Main Feedwater Valves to S/G Isolation; FC-85-62, Replacement of Component Cooling Flow Element, and FC-85-80, Redundant Fusing for Alternate Shutdown Circuits.
The technical approach and design content provided in five of the design modification packages were satisfactory based on the team's review with Omaha Public Power District personnel. The team had no further questions regarding design modifications FC-81-64, FC-84-96, FC-84-152, FC-84-179, and FC-85-80.
4.1 ANNUNCIATION OF REACTOR PROTECTIVE SYSTEM TRIP BYPASSES j
Annunciation of reactor protective system trip bypasses to the control room operator has been a long-standing requirement, but may conflict with more recent human factor recommendations regarding operator displays.
l Design modification FC-84-46, which involved conversion of a high rate of change of power trip alarm annunciator to be a high rate of change trip l
enable annunciator, was developed to address the human factor considerations.
The original Fort Calhoun design met the trip bypass indication commitment l
by causing one annunciator window to be illuminated except for brief periods during plant startup or shutdown. During the proposed conversion of this annunciator to a " dark-board" concept as recommended by human factor con-siderations, the design modification eliminated the existing trip bypass annunciation.
The proposed design modification did not address or attempt to resolve the conflict in annunciation requirements for this particular trip bypass.
(Observation 04.1-1).
I 15 4
. =....
Near the end of the inspection, Omaha Public Power District personnel were considering a slight modification to two neutron monitoring system alarms that would permit concurrent satisfaction of both the IEEE commitment and the desired dark-board annunciator concept.
4.2 ANALYSIS OF SAFETY-RELATED INSTRUMENTATION ACCURACY Analyses involving safety-related equipp nt, or critical quality elements (CQE), are required to meet commitments to ANSI N45.2.11 and applicable licensee procedures.
The team reviewed a supporting technical analysis for FC-84-140, which involved replacereat of temperature dectectors and related instruments for delta temperature power process loops used by the reactor protective system.
The OSAR-85-83 analysis prepared by Technical Services was not identified as being either safety-related or related to a Critical Quality Element and did not contain the calculation formula used to derive analysis results. The team was unable to independently review this analysis, and required assistance from Omaha Public Power District personnel to confirm the correctness of the calculation results.
The team also noted that Technical Services procedure N-TSAP-5 did not contain all of the requirements applicable to safety-related calculations as described in Generating Station Engineering procedure B-9 (Observation 04.2-1).
4.3 DESIGN ASSUMPTION IDENTIFICATION, DOCUMENTATION, AND CONFIRMATION The identification and documentation of technical assumptions made during the design process, and a timely confirmation of their validity, are important design control and design verification elements specified in ANSI N45.2.11. A number of design modification packages were examined for implicit and explicit design assumptions.
The team identified a weakness in the Omaha Public Power District instrumentation and control design process regarding the identification, documentation, and confirmation of design assumptions.
Fuse protection of certain solenoid-operated valve limit switch circuits, as described by design modification FC-84-74A, did not identify and resolve an implicit technical assumption regarding the coordination of i
two types of fuses (Deficiency D4.3-1). This omission is not in accordance with the design evaluation requirement in Generation Station i
Engineering procedure B-2. A need to confirm the coordination of two different fuse types had been noted on a design checklist by a third party reviewer; however, the design package did not provide any indication that the coordination had been confirmed or that it was appropriate.
l For design modification FC-81-102, involving engineered safety feature keylock bypass switches, the need to specify an appropriate combination l
of keylock cylinders and bypass keys to augment plant administrative 16
controls was not identified by the design engineer (Unresolved Item U4.3-2). The final design package technical description and design evaluation sections, required by procedure B-2, did not contain all of the equipment requirements necessary to establish an unambiguous design configuration. Such design provisions would help assure that only one channel could be bypassed at any given time.
4.4 CONTROL ROOM PANEL WIRING SEPARATION The team examined field cable and control room panel wiring separation criteria and implementation practices.
The team observed that Omaha Public Power District has been attempting to achieve current industry separation implementation practices for some recent design modifications. The team noted that separation criteria existed on drawings for cabling external to the control room panels, and observed its implementation during visits to the plant. An FSAR commitment made in 1970 stated that physical separation of individual channel components and wiring would be maintained wherever practicable.
The team determined that achievement of internal wiring separation within panels was a General Electric responsibility, but was unable to locate documented criteria during the inspection. The team observed that Omaha Public Power District had developed definitive separation criteria for internal panel wiring and harnesses over the past several years, and had implemented appropriate separation criteria for some panel modifications.
The team identified an ambiguity with the Omaha Public Power District position regarding the minimum separation distance of safet.y-related wiring from both redundant safety-related wiring and non-safety-related wiring within control room panels (Unresolved Item U4.4.1).
Implementation of design modification package FC-77-40 for undervoltage protection was questioned by the team because of a lack of separation among safety related wiring for redundant channels emerging from separated barrier enclosures within panel CB-4.
The need to separate these wires or to provide a justification analysis was not addressed. The design of this modification does not meet current Omaha Public Power District separation practices, and is not in accordance with a USAR section 7.3 commitment for separated and segregated engineered safeguard controls.
Similarly, the FC-81-102 design modification did not maintain adequate separation distances or justify the separation distance between safety-related and non-safety-related wiring for the planned addition of keylock bypass switches for three engineered safety feature process variables (Unresolved Item U4.4-1). The design of this modification does not meet current Omaha Public Power District intended separation practices, and the need for an analysis to justify the association of Class 1E wiring with non-Class 1E wiring to the annunciator was not identified.
An analysis has not been performed to demonstrate that Class IE circuits have not been degraded below an acceptable level, and the acceptability of use of braided conductor wiring has been assumed but has not been demonstrated. In this particular modification, the non-Class 1E wiring to the annunciator provides a common link among all four redundant ESF channels, and does not appear to comply with the USAR section 7.3 commitment for separated and segregated engineered safeguard controls.
17
4.5 CONFORMANCE WITH PROCEDURES The team reviewed a number of design modifications to assess the degree of conformance with established Omaha Public Power District procedures.
For design modification FC-82-178, which involved the addition of differential pressure indicators to a number of HEPA filter units, the design engineer did not comply with Generating Station Engineering procedure A-9 which required that a drawing sepia be issued to alert other individuals that a change was in process (Deficiency D4.5-1).
During the plant walkdown. the team identified a battery fuse block enclosure constructed of masonite and fiberboard in each of the battery rooms (Unresolved Item U4.5-3). This enclosure was not identified as a significant combustible in the fire hazards analysis. Omaha Public Power District has not confirmed that this material is not a significant combustible for the published fire hazards analysis.
5.0 ELECTRIC POWER SYSTEM The electrical modification packages scheduled for installation at Fort Calhoun during the 1985 outage were in varying stages of completion during this inspection. Of the major packages reviewed, none had progressed from the Final Design Package to third party review at the start of the inspection.
By the second week of the inspection some third party reviews had been performed but still no construction packages had been prepared even though the outage was then in progress.
The team looked at two modification packages scheduled for this outage in detail and a third package in overview.
The team also looked in detail at an additional modification package completed in an earlier outage that had a direct impact on one of the 1985 modifications reviewed by the team.
5.1 DIRECT CURRENT SYSTEM MODIFICATIONS The team reviewed changes to the power sources and loads as detailed in modification package MR-FC-84-119.
This package included changes to the station batteries (which would reduce the available capacity), the battery chargers (which would increase their capability to carry the steady state de load), and the instrument inverters (which would add additional load considerations on the de system).
The team reviewed the effect which removing two cells from the batteries would have on the required capacity of the battery.
Omaha Public Power l
District correctly based this determination upon sizing calculations l
performed using a higher permissible limit on cell discharge voltage.
As l
part of this review, the team also reviewed completed modification MR-FC-79-03, Replacement of Station Batteries.
The battery profile established in the 1979 modification formed the sole basis for the latest calculation input.
The team found no justification for using this earlier unchecked input data (Deficiency 05.1-1).
The team reviewed the replacement of the old battery chargers with new, larger battery chargers and found that insufficient consideration had been given to the interface between the DC Switchboard and the larger charger.
Under the new design, the battery may not be able to be recharged following a test or design basis discharge (Unresolved Item U5.1-2).
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18 1
The team reviewed the power cable sizing changes required because of the larger equipment being added to the system and noted that no standard interpretation of cable sizing for cable routed in cable tray existed for Fort Calhoun (Observation 05.1-3).
5.2 RACEWAY FIRE PROTECTION The team reviewed the analysis performed to determine the effect the fire protective wrapping would have on the enclosed cables.
This work was to be performed under modification package MR-FC-85-25 in response to Appendix R concerns regarding redundant power supplies for the pressurizer heaters being routed through the same fire zone.
Omaha Public Power District proposed to reroute the existing BUS 3 motor control center feeders through conduit and proposed to provide a one hour fire protection for these conduits by wrapping them in multiple layers of 3M Company "Interam E-50A" fire protection materials.
The team determined that Omaha Public Power District used cable derating factors obtained from the 3M Company based upon an internal 3M Company computer program.
The team also determined that Omaha Public Power District personnel were not familiar with the computer input or output data supplied by 3M.
Omaha Public Power District failed to verify the computer code used by 3M or even request 3M to supply correlation test data before they were questioned on this by the team (Deficiency 5.2-1).
Regarding this item the team concluded, based upon subsequent test data supplied to Omaha Public Power District by 3M, that the original derating factors used by Omaha Public Power District were not in agreement with the test results. Based upon the original modification package design, degradation to power cables could have resulted to these motor control centers feeders and to other power cables in similarly fire protected raceways in the future.
- 5. 3 LOAD CENTER TRANSFORMER REPLACEMENT The team reviewed the effect changing load center transformers would have on the electrical power transformers.
Replacement of these transformers is scheduled for the 1985 outage under modification package MR-FC-84-105.
The team reviewed the specification data for the new transformers.
Manufacturing of the Fort Calhoun transformers had not been completed so that no production test data was available for review.
The team noted that the responsible engineer had reviewed the transformer impedance requirements for compatability with the existing switchgear and had discovered a problem with the transformers that had been replaced in an earlier outage.
6.
DESIGN CHANGE CONTROL The team performed a partial review of the Omaha Public Power District design change process and safety evaluations associated with outage modifications.
A limited review of completed emergency modifications was also conducted.
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6.1 SAFETY EVALUATIONS The team evaluated final design package safety evaluations for adequacy in accordance with the requirements of 10 CFR 50.59.
Safety evaluations were reviewed for modifications planned for this outage and for previous work accomplished as emergency modifications.
The team reviewed Fort Calhoun Station Standing Order No. G-46,
" Evaluation of Procedures, Procedure Changes, Tests and Experiments for Safety Evaluation and Status as an Unreviewed Safety Question." This procedure provides guidance for the preparation of written safety evaluations.
The procedure includes the subset of items listed in Technical Specification 5.5.1.7.b which requires the Plant Review Committee to render determinations in writing with regard to whether or not items constitute unreviewed safety questions. Other procedures reviewed by the team also detail requirements for the performance of safety analysis.
Generating Station Engineering procedure B-2,
" Production of Design Description and Evaluation," for example, stipulates that safety analysis must be performed for safety-related Critical Quality Element structures, systems and components.
The procedure additionally requires safety analysis for certain non-safety-related modifications if such modifications have a reasonable possibility of damaging safety-related components.
The team noted several problems with the licensee's procedures regarding the performance of safety analysis / evaluations.
One problem noted by the team was the failure of the licensee to perform safety analyses for certain non-safety-related changes, as required by 10 CFR 50.59.
10 CFR 50.59 allows licensees to change the facility as described in the FSAR, without prior NRC approval, provided the change does not involve a change in Technical Specifications or an unreviewed safety question.
10 CFR 50.59 is also permissive for procedures (as described in the FSAR) and for tests and experiments (not described in described in the FSAR).
An unreviewed safety question is deemed to be involved (a) if the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the safety analysis report may be increased; or (b) if a possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis report may be created; or (c) if the margin of safety as defined in the basis for any technical specification is reduced.
The team found that safety evaluations were not being done in all cases for non-Critical Quality Element (non-safety-related) systems that were described in the USAR.
Five non-Critical Quality Element modifications were noted to have final design packages issued with no safety evaluation accomplished:
20
Modification Request No.
Title 483-175 Feedwater Regulating System Instrumentation Replacement 485-008 Boric Acid Addition System 4748-057 Power System Stabilizer 483-174 Reactor Regulating System Steam Dump and Bypass Alarm 483-90 Replace LP Feedwater Heaters Each of the above affected systems or equipment were described in the USAR in sufficient detail that completion of the modifications would require changes to USAR text, drawings or tables to accurately represent the newly changed systems.
A safety evaluation is required by 10 CFR 50.59 for modifications such as the above even though the equipment and systems are non-safety-related (Deficiency 06.1-1).
One of the major jobs being accomplished during the 1985 outage at Fort Calhoun was the installation of dams in the steam generator primary head nozzles.
These were contracted to Nuclear Energy Services, Inc. by the Technical Services Group of Omaha Public Power District and will allow refueling to proceed simultaneously with steam generator tube inspections.
The team requested to review the 10 CFR 50.59 safety analysis associated with the use of these nozzle dams.
The team was informed that the dams were considered a tool and not a modification, and therefore that Generating Station Engineering had not been required to perform a 10 CFR 50.59 safety analysis.
The team was told that a safety analysis would be performed by Technical Services in accordance with Standing Order G-46 prior to use of the nozzle dams.
The team was concerned regarding the diverse nature of the safety analyses performed pursuant to 10 CFR 50.59 and those performed to implement Technical Specification requirements, and questioned the licensee's methodology which results in bypassing the responsible design organization (Generating Station Engineering) for performing safety evaluations for this type of facility change.
The team found also that final design package 10 CFR 50.59 reviews were not accomplished and documented in all cases by Generating Station Engineering design engineers prior to accomplishment of emergency plant modifications and subsequent plant operation.
Three cases were noted; modifications for l
correctin'g DC grounds on Critical Quality Element Safety Injection valves j
(MR 484-84) and diesel generator speed sensing power supply modifications (MRs 483-129 and 483-152) (Unresolved Item U6.1-2).
i The team also noted that in general, the safety evaluations reviewed l
tended to be quite brief with limited detail and analysis provided in l
them.
They simply answered the three questions posed by 10 CFR 50.59 with very little explanation provided to give the team confidence that all safety concerns were being analyzed.
In some cases, where final design package and construction package safety evaluations were accomplished, the wording was identical.
This indicated to the team that there was a lack of independent consideration between the final design and construction safety evaluations as required by Omaha Public Power District procedures.
In addition, unless these thought processes are adequately documented, each reviewer in the approval circuit must reconstruct and reanalyze scenarios that may have already been accomplished by the design engineer.
21 L
Another problem concerns the lack of a procedural requirement to evaluate whether or not a proposed change (modification, procedure, test or experiment) involved a change in the Technical Specifications; and therefore, whether or not it can be implemented without prior NRC approval.
The team identified one modification which internally interprets the technical specifications to prevent the creation of malfunction of a different type than previously analyzed in the FSAR.
Specifically, the replacement of the vital ac inverters creates a possibility of powering the non-interruptible (battery powered) buses which the inverters supply from interruptible (off-site power or diesel generators) sources.
If more than one of these buses was powered from interruptible power the plant would be in an unanalyzed condition.
To address this concern, the engineer stated that if an inverter is in bypass (bus powered from interruptible ac) the inverter would be considered inoperable per the Technical Specifications.
The possibility of a different type of accident may have been created even though the associated safety evaluation contains an interpretation of Technical Specifications which, if implemented, would lessen the probability of occurrence of such an accident (Observation 06.1-3).
6.2 FINAL DESIGN PACKAGES The team conducted a limited evaluation of final design packages of planned outage modifications for adequacy with regard to the licensee's implementation of its commitments to ANSI N45.2.11 design control requirements.
Emergency modifications were also reviewed for issuance of af ter-the-fact final design packages.
After review of numerous final design packages for this outage, the team considered that design inputs were not clearly specified in the packages.
The final design packages were formatted with headings of Design Basis, Technical Description and Design Analysis but the text generally represented a narrative account of the problem and solution with no clear specification of design inputs.
ANSI N45.2.11, to which Omaha Public Power District is committed, requires in part that "The design input be r
specified...to provide a consistent basis for making design decisions, l
accomplishing design verification measures, and evaluating design changes." Design inputs were not found to be clearly spelled out in the final design packages to meet this requirement.
In addition, the Checker's Checklist-Design Package, provided in Generating Station Engineering Procedure B-2, asks "Are design inputs correctly selected and incorporated into the design?".
The team considers this step of the checking process cannot be easily or accurately accomplished if design inputs are not clearly specified as required by the ANSI N45.2.11.
During review of emergency modifications, the team noted that what it considers excessive time had been taken to issue the final design packages associated with six modifications.
Omaha Public Power District procedure G-21 allowed completion of emergency modifications in the plant prior to completing the final design package but provided no guidance for timely issue of after-the-fact design packages.
Two of the six modifcations had after-the-fact design packages issued, but one was 11 months and the other 42 months after completion of the plant modification.
The remaining four 22 l
emergency modifications did not have after-the-fact design packages issued at the time of this inspection.
These plant modifications had been completed for a period ranging from 16 to 32 months.
Even though ANSI N45.2.11 does not specifically address timely closure of work packages, it is desirable from a system acceptance standpoint to reduce the amount of time to prove that an emergency modification has been implemented properly.
A tracking system did exist for projects not closed out but insufficient management attention appeared to be directed toward review of the listing and closeout of the items (Observation 06.2-1).
One of the modifications (MR 83-158) being accomplished during the current outage arose from the inadequate implementation of an earlier modification performed on an emergency basis.
During review of modification MR 83-158, which adds accumulators to air operated (fail open) steam supply valves (YCV 1045 A/B) to the steam driven AFW pump, the team determined that the modification had been initiated to allow closeout of another modification (MR 78-43) performed on an emergency basis in March 1980. When the closecut review of MR 78-43 was conducted in October 1983 (a period of time which the team considers excessive), Generating Station Engineering determined that the modification, as installed, violated the General Design Criteria 57 requirement for the ability to remote-manually isolate a closed system penetrating containment.
A portion of original modification which added accumulators to the steam supply valves to address containment isolation concerns had not been accomplished.
The licensee closed out the original modification and started a new modification to provide the accumulators.
The "after-the-fact" 10 CFR 50.59 safety evaluation determination that no unreviewed safety question existed was based upon future work to be done on another modification.
In January 1985, after additional internal discussions between licensee site, Technical Services and Engineering.
personnel, a decision was made to prioritize the installation of the accumulators to be accomplished in the Fall 1985 refueling outage and to revise emergency procedures to alert operators to the potential need to locally isolate the AFW steam supply line following a steam generator tube rupture.
A determination was made that an unreviewed safety question did not exist and that this was not a reportable event (Deficiency D6.2-2).
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7.0 BACKGROUND
7.1 MEETINGS Interim Status Briefing An interim status briefing on the status of the safety systems outage modifi-cation inspection program was conducted on October 8, 1985 at the conclusion of the design portion of this program.
The following persons attended the meeting:
Name Title Organization O rchitzel T E Leader NRC - IE P. Surber Sect. Mgr. - GSE OPPD K. J. Morris Manager - QA OPPD D. Wittke V.P. - Engineering OPPD J. K. Gasper Mgr. Administrative Sycs.
OPPD R. L. Andrews Div. Mgr. - Nuclear OPPD Production W. C. Jones Vice President OPPD J. J. Fisicaro Supe visor - Nuclear OPPD Regulatory and Industry Affairs J. C. Barker Team Leader, Outage Insp.
NRC - IE J. E. Konklin Chief, Special Programs NRC - IE Section B. Grimes Director, Div. of Q.A.,
NRC - IE Vendor & Tech. Training J. L. Milhoan Chief, Licensing Section, NRC - IE Quality Assurance Branch G. Overbeck Mechanical Systems NRC - WESTEC A. H. Saunders Reactor Engineer NRC - IE M. Eidem Mgr. - GSE Mech.
OPPD R. L. Jaworski Section Manger - Tech.
OPPD Services T. L. Patterson Manager - Technical Support OPPD S. K. Gambhir Manager - GSE Electrical and OPPD Nuclear L. Stanley Instrumentation & Control NRC - Zytor, Inc.
A V. Du Bouchet Mech. Comp.
NRC - Cons. Engr.
S. W. Ky NSC, Senior Researcher Nuclear Safety Center, Korea G. Morris Electrical Consultant NRC - WESTEC R. Lloyd Reactor Engineer NRC - IE M. E. Murphy Project Inspector NRC - RIV W. Gary Gates Manager - Fort Calhoun OPPD Station During the Interim Status Briefing, the team presented the significant findings which had been identified during the inspection.
Periodic management briefings were also held during the inspection.
24
t 7.2 PERSONS CONTACTED Name Title Organization M. Liden Lead Mechanical Engineer OPPD, GSE D. Ecklund Mechanical Design Engineer OPPD, GSE L. Gundrum Mechanical Design Engineer OPPD, GSE R. Eurich Mechanical Design Engineer OPPD, GSE S. Gambhir Manager, Electrical & Nuclear OPPD, GSE Engineering P. Surber Section Manager OPPD, GSE J. Fisicaro Supervisor-Nuclear Regulatory OPPD and Industry Affairs B. Livingston Manager GSE Document Control OPPD, GSE J. Albers Document Control OPPD, GSE R. Lewis Supervisor - Mech./GSE OPPD R. C. Kellogg Supervisor - Mech./TS OPPD M. E. Eidem Manager - Mech./GSE OPPD T. L. Patterson Manager - Technical Support OPPD R. L. Jaworski Section Manager /TS OPPD J. R. Tucker Electrical Design Engr./GSE OPPD J. E. Bentzinger Supervisor - Procurement QA OPPD H.L. Little Supervisor, Electrical OPPD, GSE H.J. Faulhaber Supervisor, Electrical 0 PPD, GSE L.W. Jackson Lead Engineer, Electrical /I&C OPPD, GSE W.C. Gartner Senior Engineer, Electrical /I&C OPPD, GSE R.P. Clemons Senior Engineer, Electrical /I&C OPPD, GSE B.R. Briganti Engineer, Electrical /I&C OPPD, GSE R.R. Ronning Engineer, Electrical /I&C OPPD, GSE N.B. McShannon Senior Designer OPPD, GSE R.W. Coen Senior Designer OPPD, GSE E. Erickson Design Verification Consultant.
SWEC R. Mehaffey Supervisor I&C/ Electrical Technical OPPD Services D. Haas Mechanical Design Engineer OPPD, GSE D. Deboer Mechanical Design Engineer OPPD, GSE i
i 25
LIST OF DEFICIENCIES, UNRESOLVED ITEMS AND OBSERVATIONS Item Title D2.1-1 (Deficiency)
Lack of Design Analysis to Support Sizing of Air Accumulators for Valves YCV 1045 A/B D2.1-2 (Deficiency)
Seismic Requirements not Specified in MR-FC-83-158 Procurement Documents 02.1-3 (Observation)
Vendor Exceptions to Specifications not Reflected in Procurement Document 2.1-4 N/A Item Number not Used 02.1-5 (Observation)
Procedural Error Caused Seismic and Stress Analysis for MR-FC-83-158 Not To Be Filed In Modification File D2.1-6 (Deficiency)
Failure to Follow Procedural Requirements for a Normal Modification Resulting in Lack of Required Design Verification Review D2.1-7 (Deficiency)
Incomplete Installation / Testing Procedure in Construction Package for MR-FC-83-158 02.1-8 (Deficiency)
Incorrect Information on Flow Diagram for Main Steam System D2.1-9 (Deficiency)
Incorrect System Description Statements U2.1-10 (Unresolved)
Use of Fluorocarbon-Elastomer Material in High Radiation Environments D2.2-1 (Deficiency)
Incorrect Design Input in Calculation Associated with MR-FC-81-21B D2.2-2 (Defic'ency)
Incomplete Consideration of CQE and Seismic Class I Requirements for Portions of MR-FC-81-21B D2.2-3 (Deficiency)
Incomplete Installation / Testing Procedure Performed for MR-FC-81-21B 02.2-4 (Observation)
Incomplete Modification File for a Completed Modification D2.2-5 (Deficiency)
Incorrect Information on Instrument Air Diagram D2.2-6 (Deficiency) 10 CFR 50.59 Safety Evaluation Based Upon an Incorrect Assumption and Analysis Methodology A-1
Item Title D3.1-1 (Deficiency)
Balance of Plant Design Specifications i
D3.1-2 (Deficiency)
Design Temperatures for Safety-Related Piping U3.1-3 (Unresolved)
Small Bore Pipe Support Spacing 03.1-4 (Observation)
Seismic Qualification of Valves Installed in Class I Piping Systems U3.2-1 (Unresolved)
MR-FC-84-61 Design Input Source and Use D3.2-2 (Deficiency)
MR-FC-83-158 Installation Procedure D3.2-3 (Deficiency)
MR-FC-84-162 Calculation D3.2-4 (Deficiency)
Junction Box Supports 03.2-5 (Observation)
Containment Pressure Switch Seismic Qualification D3.2-6 (Deficiency)
Steam Generator Nozzle Dams D3.2-7 (Deficiency)
YCV 1045B Valve Restraint 04.1-1 (Observation)
High Power Rate of Change Trip Bypass 04.2-1 (Observation)
Delta T Power Loop Analysis D4.3-1 (Deficiency)
Limit Switch Circuit Protection by Fusing, MR-FC-84-74A U4.3-2 (Unresolved)
ESF Bypass Switch Keylock Provision, MR-FC-81-102 04.3-3 (Observation)
Procurement Requirements on Equioment Vendors U4.4-1 (Unresolved)
Design Basis Physical Separation Within Panels D4.5-1 (Deficiency)
Drawing Changes by Procedure A-9, MR-FC-82-178 04.5-2 (Observation)
Flow Element Design Basis Conditions U4.5-3 (Unresolved)
Battery Room Fire Hazard Analysis D5.1-1 (Deficiency)
Battery Sizing Calculation US.1-2 (Unresolved)
Battery Charger /DC Bus Coordination e
f i
A-2
. _ - =
Item Title 1
05.1-3 (Observation)
Power Cable Sizing Criteria 05.1-4 (Observation)
Pre-operational Test Requirements 05.1-5 (Observation)
Inverter Sizing without Analysis 05.1-6 (Observation)
Design Interface Control D5.2-1 (Deficiency)
Fire Wrap Protection for Cable Raceways D6.1-1 (Deficiency)
Safety Evaluations for Non-Safety-Related Systems Described in the USAR U6.1-2 (Unresolved)
Safety Analyses for Emergency Modifications 06.1-3 (Observation)
Vital AC Inverter Bypass Mode 06.2-1 (Observation)
Untimely Closeout of Emergency Modifications D6.2-2 (Deficiency)
Modifications to AFW Turbine Steam Supply Valves 1
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A-3
02.1-1 (Deficiency) Lack of Design Analysis To Support Sizing Of Air Accumulators For Valves YCV 1045 A/B DESCRIPTION:
Steam supply to the Auxiliary Feedwater turbine pump is supplied from a steam header fed by two steam branch lines, one from each steam generator.
The steam header is normally pressurized up to isolation valve YCV-1045 through normally open isolation valves YCV-1045A and YCV-1045B in the branch lines.
These isolation valves are pneumatically operated and can be remote manually operated from the control room.
In the original system design, valves YCV-1045 A and B were designed to fail open on loss of instrument air, and valve YCV-1045 was designed to fail close.
A modification request, MR-FC-78-43 (Reference 1), was initiated on an emergency basis in 1979 to redesign the valve operator for YCV-1045 and replace it with a fail open operator.
This modification request was initiated in September, 1978 after the turbine pump failed to start during operability testing because of inadvertent closure of an instrument air supply valve to YCV-1045 actuator (LER-78-030).
To enable remote manual isolation in the event of a steam generator tube rupture with a concomitant loss of non-safety-related instrument air, air accumulators were to be added to the valve actuators for YCV-1045 A and B; however, these accumulators were not installed prior to returning the plant to power operation.
During closecut of FC-78-43, a new engineering evaluation and assistance request, EEAR FC-83-158 (Reference 2), was initiated to install the air accumulators.
In a January 15, 1985 memorandum (Reference 3), MR FC-83-158 was scheduled for completion during the Fall-1985 planned outage.
The Final Design Description (Reference 4) states that each accumulator will be sized to provide air to the valve for one hour.
To assess the implementation of the design process for modifications, the team reviewed the sizing calculations.
Design analysis does not exist to confirm sizing of the air accumulators.
The team found that a calculation does not exist which demonstrates that a sufficient stored volume of pressurized air will be available to close YCV-1045 A and B assuming a loss of instrument air and minimum initial accumulator. pressure.
The valve is spring actuated to open, and sufficient air pressure must be provided to overcome spring pressure and approximately 1100 psi differential pressure across the globe valve during closure.
The team was informed that a sizing calculation was not performed for this modification package.
The design engineer indicated that he referred to calculations in a completed modification and used engineering judgement to conclude that the current design was adequate.
The team found no documentation of the engineering judgement and requested for review the sizing calculations referred to by the design engineer.
These calculations were not available during the inspection.
BASIS:
The licensee committed to implement ANSI N45.2.11 (Reference 8) for design activities associated with modifications of safety-related structures, systems, and components.
Contrary to the requirements of this standard, a design analysis was not performed in a planned, controlled, and correct manner. In addition, the design activity was not traceable from design input through to design output.
A-4
REFERENCES 1.
Document Control File for MR FC-78-43, Failure Mode of YCV-1045.
2.
EEAR FC-83-158, Air Accumulators for YCV-1045 A/B, November 8, 1983.
3.
OPPD Memorandum TS-FC-85-42H, Review of Failure Mode Modification on YCV-1045 A/B Steam Supply Valves to Steam-Driven AFW Pump, FW-10, January 15, 1985.
4.
OPPD Final Design Description MR-FC-83-158, Air Accumulators for YCV-1045 A/B CQE, Rev. O, February 14, 1985.
5.
OPPD Generating Station Engineering Procedures Manual, Revision of August 1985.
6.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Opera-tion), Rev. 2, February 1978.
7.
ANS-3.2/N18.7, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants Revision of N18.7-1972, February 19, 1976.
8.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
4 A-5
02.1-2 (Deficiency) Seismic Requirements Not Specified In MR-FC-83-158 Procurement Documents DESCRIPTION:
The team examined the procurement documents for MR-FC-83-158 to determine if appropriate requirements had been included.
The air accumulators and associated tubing and valves serve a post-accident function to close YCV-1045 A and B.
These control valves are classified as seismic Class I in accordance with Appendix F of the USAR; therefore, the air accumulators and associated valves and tubing are considered seismic Class I.
The procurement specifications for isolation and check valves (References 2 and 3) do not specify seismic requirements.
The team noted that third party design verifications (References 4 and 5) of these two specifications concluded that the design inputs were correctly selected and incorporated into the design.
BASIS:
Omaha Public Power District has committed to implement the guidance of ANSI N45.2.11 (Reference 8).
ANSI N45.2.11 requires that the applicable codes, standards and regulatory requiren ints be properly identified and properly addressed.
Contrary to this requirement, the design verifier did not ensure that the seismic requirements were included in the procurement documents.
REFERENCES 1.
OPPD Critical Quality Elements (C.Q.E.) List, Rev. 2, May 24, 1985.
2.
OPPD Purchase Order No. 72533, SS-6C-10 NUPRO 3/8" Check and Relief Valve, August 15, 1985.
3.
OPPD Purchase Order No. 70650, SS-1KS6 WHITEY 3/8" Forged Body, Shut-off Valves, July 19, 1985.
4.
OPPD Design Verification Checklist-Specifications for MR-FC-83-158, Instrument Air Check Valve Specifications, September 19, 1985.
5.
OPPD Design Verification Checklist-Specifications for MR-FC-83-158, Instrument Air Isolation Valve Specification, September 19, 1985.
6.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Opera-tion), Rev. 2, February 1978.
7.
ANS-3.2/N18.7, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants Revision of N18.7-1972, February 19, 1976.
8.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
A-6 I
m-w-
02.1-3 (Observation) Vendor Exceptions to Specifications Not Reflected in Procurement Document DESCRIPTION:
Modification request, MR-FC-83-158, is a normal modification to install an accumulator on each of two valves, YCV-1045 A and B.
The Critical Quality Elements List (Reference 1) states that instrument air system air accumulators and associated piping and valves that supply air to valves that must function post-accident are considered critical quality elements.
Because YCV-1045 A and B perform a post-accident safety function, the instrument air accumulators and associated tubing and valves are also considered Critical Quality Elements.
The team examined the procurement documents for MR-FC-83-158 to determine if the vendor proposed equipment met or exceeded specification requirements.
The specification for Critical Quality Element for instrument isolation valves required that the storage be in compliance with ANSI N45.2.2, Level C and that the packaging be in accordance with vendor procedure WS-23 with engineer approval required.
In a letter (Reference 2), the vendor took exception to the storage requirement stating that his valve supplier does not attempt to conform to ANSI N45.2.2, Level C.
Despite this exception to the specification requirements, the purchase order (Reference 3) was issued to the vendor indicating that packaging, shipping, storage and handling shall meet or exceed the requirerents of ANSI N45.2.2, Level C.
The team believes that documentation of the acceptability of the vendor exception would enhance the conformance of the equipment with present procure-ment document requirements.
REFERENCES 1.
OPPD Critical Quality Elements (CQE) List, Rev. 2, May 24, 1985.
2, Omaha Valve & Fitting Company letter from S. Pendleton to H. Frazier (0 PPD), July 17, 1985.
3.
OPPD Purchase Order No. 70650, SS-1KS6 Whitey 3/8" Forged Body, Shut-off Valves, July 19, 1985.
4.
OPPD Quality Assurance Plan 4.1, Procurement Process, Rev. O, September 1, 1984.
1 A-7 i
- - - - ~ -,.
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.-r
02.1-5 (Observation) Procedural Error Caused Seismic And Stress Analysis For MR-FC-83-158 Not To Be Filed In Modification File DESCRIPTION:
The seismic and stress analysis (Reference 1) for the air accumulators was prepared initially on August 12, 1985.
Since then the analysis has been checked, third party reviewed, revised, rechecked, and was undergoing a second third party review during the design inspection.
The team found no documentation associated with this calculation package in the modification file, and it is uncertain that the appropriate documentation would have been filed in the modification file because the modification file number was not identified on the memorandum (Reference 2) routing the calculation for final review.
Omaha Public Power District does not maintain calculations as living documents (i.e., calculations are not maintained in a calculation file and kept current as plant systems, structures, components are modified throughout the life of the plant).
Instead, calculations are performed, as required, for each modification.
As a consequence, the modification file is the only controlled location for retention of design calculations.
The inclusion of design calculations is left to the discretion of the Design Engineer.
The team was informed that the subject calculation was a " generic" calculation not applicable to a particular modification package.
As such the generic calculation should have been referenced in the modification file.
The team found that the control and use of generic calculations are not described in the General Station Engineering procedures.
The team found that calculations of this nature were the exception rather than the rule.
For the modification packages reviewed, the team found no references to generic calculations.
A better control process for generic calculations would allow enhanced retrieval, use and revision of such calculations.
REFERENCES 1.
OPPD Calculation, Generic Air Accumulators using Propane Tanks Built to l
00T Spec. 4BA-240, Rev. O, August 12, 1985.
2.
OPPD Memorandum from Department Manager to B. R. Livingston, Design j
Review Generic Air Accumulator Calculations, September 10, 1985.
{
A-8
D2.1-6 (Deficiency) Failure to Follow Procedural Requirements For A Normal Modification Resulting In Lack Of Required Design Verification Review DESCRIPTION:
The Generating Station Engineering (GSE) Procedures Manual describes the responsibilities of Generating Station Engineering personnel, the types of modification requests, the information to be included in preparation of a modification package, and steps to document field changes and closecut.
Three types of modifications are described. These are normal, emergency, and minor.
A minor modification does not involve any Critical Quality Element (CQE) components.
A normal modification involves the preparation of a preliminary design package (optional), a final design package including third party review, and a construction package with third party review.
For an emergency modification request, the same procedure is applied except that certain approvals may be accomplished by telephone and the completion of the documentation may be accomplished following completion of the modification.
For emergency and normal modifications, the preliminary design package is normally waived.
After an emergency modification is installed, preparation of an "after-the-fact" (ATF) final design package and subsequent reviews in accordance with the normal modification are performed.
Modification request, MR-FC-83-158, is a normal modification to install an accumulator on valves YCV-1045 A/B.
This modification was initiated in 1983 to correct partial completion of another modification accomplished on an emergency basis in 1980.
On February 19, 1985, the final design package (Reference 1) for this modification was sent for third party review.
On February 26, 1985, the third party reviewer completed his review and determined that the final design package was not in compliance as documented on a design document verification record (Reference 2).
On June 10, 1985, the construction package (Reference 3) was sent to the Plant Manager for approval.
MR-FC-83-158 was not treated as required for a normal modification in accordance with Design Procedure B-2 (Reference 4).
The team found that a construction package was prepared even though the design verification of the final design package had not been completed.
For a normal modification, the team was informed that the preparation of a construction package prior to completion of the finsi design package is an accepted practice.
From interviews, the team determined that it was not uncommon for design verifications to be completed after normal modifications had been installed.
It appears that this practice is similar to that used for emergency l
modifications.
This situation was further aggravated by the Design Engineer who made a determination that the construction package did not require third party review and who signed a memorandum (Reference 5) for the Department Manager stating that a third party review was not required.
BASIS:
Contrary to Generating Station Engineering Design Procedure B-2 Item 2.5.3, which states that after approval of the final design package, for I
normal modifications only, the Design Engineer will prepare the Construction l
Package, a construction package for a normal modification was prepared and l
completed prior to approval of the final design package.
A Construction Package Design Verification was not performed, contrary to procedure item 2.7.3, which states that a design verification review was required if the l
construction package involved the installation of Critical Quality Element components.
A-9
REFERENCES I
1.
OPPD Memorandum GSE-FC-85-66 (M7-C), Final Design RevicW of MR-FC-83-158
" Air Accumulators for YCV-1045 A/B", February 19, 1985.
2.
OPPD Design Document Verification Record / Routing Sheet, Project / Design Modification FC-83-158,. Routing No. 373, February 26, 1985.
3.
OPPD Memorandum GSE-FC-85-480 (M8), Construction Package for MR-FC 158, June 10, 1985.
4.
GSE Design Procedure B-2, Production of Design Description and Evaluation, Rev. 1/84.
5.
OPPD Memorandum from Department Manager to B. R. Livingston, Design Review for MR-FC-83-158, June 11, 1985.
I i
e A-10 d
D2.1-7 (Deficiency) Incomplete Installation / Testing Procedure in Construction Package for MR-FC-83-158 DESCRIPTION:
Modification request MR-FC-83-158 is a normal modification to install an accumulator on each of two valves, YCV-1045 A and B.
These instrument air accumulators were to be installed to permit the remote manual isolation in the event of a steam generator tube rupture with a concomitant loss of non-safety-related instrument air.
YCV-1045 A and B are normally closed steam admission valves located in steam branch lines feeding the auxiliary feedwater turbine pump, and they fail open on loss of instrument air.
These control valves are classified as seismic Class I and as Critical Quality Elements (i.e., safety-related).
YCV-1045 A and B are 2-inch globe valves which may be required to shut against a differential pressure of approximately 1000 psig.
The post modification testing procedure (Reference 1) does not test this design function.
During the installation, YCV-1045 A and B are closed; therefore, the valves are closed prior to commencing post-modification testing.
The first step of the test, Step 6.6, pressurizes the installation with normal instrument air supply causing the actuator above the diaphragm to be filled.
Step 6.7 opens the valve handwheels of valves YCV-1045A and YCV-1045B; however, the valves remain in the closed position because air has not been vented from above the diaphragm.
Step 6.8 directs that the installation be isolated from the normal instrument air header using the root valve and that the actuator should be monitored for one hour to ensure the valves remain shut with air supplied by the accumulators alone.
As a consequence, the test procedure does not use the pressurized volume of the accumulator to shut the valves.
In addition, no testing adjustment is made to test the capability of the 2-inch globe valves to shut against high differential pressures, nor is an acceptance criterion provided for acceptable air leakage.
The only acceptance criterion is that the valves must remain shut for one hour.
The team also noted that Step 6.8 requires the pressure of air in the accumulator to be noted if the valve does not open.
However, there is no pressure gauge on the accumulator or intervening piping.
BASIS:
Omaha Public Power District has committed to Regulatory Guide 1.33 (Reference 5) which endorses ANSI N18.7 (Reference 6).
This standard requires that modifications which affect functioning of safety-related structures, systems, or components be inspected and tested to confirm that the modifications or changes reasonably produce expected results and that the change does not reduce safety of operations.
These test procedures are to include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.
i Contrary to these requirements, the test procedure would not have confirmed I
that the modification produced expected results and did not have an acceptance criterion for acceptable air leakage.
REFERENCES 1.
OPPD Installation Procedure MR-FC-83-158, Air Accumulators for YCV-1045 A/B, Rev. O, June 10, 1985.
2.
OPPD Checker's Checklist - Construction Package MR-FC-83-158, Air Accumulators for YCV-1045 A/B, June 10, 1985.
A-11
3.
OPPD Memorandum from Department Manager to B. R. Livingston, Design Review for MR-FC-83-158, June 11, 1985.
4.
OPPD Design Verification Checklist - Work Instructions and Test Procedures, MR-FC-83-158 Air Accumulators for YCV-1045 A/B, February 26, 1985.
5.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Rev. 2, February 1978.
6.
ANSI N18.7/ANS 3.2, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants, February 19, 1976.
1 i
i A-12
D2.1-8 (Deficiency) Incorrect Information On Flow Diagram For Main Steam System DESCRIPTION:
During the course of the inspection, the team reviewed design aspects of various modifications with respect to the information contained on system flow diagrams. The following inconsistencies and errors were identified during the team's review of the steam system flow diagram.
System Description III-2 (Reference 1), steam system description, states that the main steam isolation bypass valves, HCV-1041C and HCV-1042C, are horizontally mounted, motor-operated, 2-inch globe valves.
These valvas are piped into the valve body of their respective i;.ain steam isolation valves.
Review of the valve drawings (Reference 2) shows that steam passes through ths bypass line upsteam of the disc associated with the main steam isolation valves, flows through HCV-1041C and back into the valve body of the main steam isolation valve downstream of the valve's disc, HCV-1041C is cracked open and steam flows through the non-return valve (HCV-1041B). When pressures and temperatures have equalized, the main steam isolation valve is opened.
The main steam isolation valves and the non-return valves are within the Class 2 boundary.
Flow Diagram 11405-M-252 (Reference 3) incorrectly represents the piping arrangement associated with the bypass valves and the auxiliary feedwater steam warmup lines.
The drawing indicates that the piping to the bypass valves taps off the upstream side of the disc and returns to the upstream side, versus the correct return to the area between the main steam isolation valve and its associated reverse flow check valve.
In addition the piping connected downstream of the bypass valve is indicated as non-safety by a flag.
This piping also supplies the warmup line for the auxiliary feedwater steam headers, which is also incorrectly indicated as non-safety.
These lines tap l
off the downstream side of the bypass valves and are piped to the downstream side of YCV-1045 A and B through normally open isolation valves MS-336 or MS-337.
The portion of the piping from the main steam isolation bypass isolation valves to either MS-336 or MS-337 and the associated branch line to the main steam isolation valve body is incorrectly depicted as non-safety.
The team noted that Omaha Public Power District's Critical Quality Elements (CQE) List (Reference 4) is a system level Q-List which relies in part on the correct classification on system flow diagrams.
i During the inspection, Omaha Public Power District acknowledged the error and l
committed to correct the flow diagram.
BASIS:
Omaha Public Power District committed to Regulatory Guide 1.64 (Reference 5) which endorses ANSI N45.2.11 (Reference 6).
This standard requires that personnel use proper and current drawings and design inputs.
Contrary to this requirement, the steam system flow diagram was not correct or current with the as-installed arrangement in the plant.
REFERENCES 1.
OPPD System Description III-2, Steam System, Revised August 16, 1984.
2.
Schutte & Koerting Company Drawing 69-XC-20, Assembly Drawing 28X24-600**
Main Steam Trip Valve, Rev. 8, March 5, 1985.
A-13
3.
OPPD Drawing Numoer 11405-M-252, Flow Diagram Steam, Rev. 33, June 21, 1984.
4.
OPPD Critical Quality Elements (CQE) List, Rev. 2, May 24, 1985.
5.
Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2, June 1976.
6.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
+
J l
A-14
D2.1-9 (Deficiency) Incorrect System Description Statements DESCRIPTION:
During the team's review of various modification packages, Omaha Public Power District's system descriptions were examined to confirm system design bases.
The following errors or inconsistencies were identified in the system descriptions reviewed.
a.
Auxiliary Feedwater System Description III-4 (Reference 1) states that steam admission valves, YCV-1045 A and B, each have 3/8 inch unvalved bypass lines that serve to maintain warm steam lines up to FW-10 isolation valve YCV-1045.
Contrary to this description, the team determined that the source of warming steam to the auxiliary feedwater turbine line downstream of YCV-1045 A and B passes through normally open manual valves MS-336 and MS-337, respectively. These valves are shown on Steam System Flow Diagram (Reference 2) and related physical piping diagrams.
b.
Modification MR-FC-21B changed valves HCV-438B and HCV-438D (outside containment component cooling water isolation valves for the reactor coolant pump lube oil coolers and seals) from failed closed to fail i
open and added air accumulators to permit the valve operator to keep the valves closed until action could be taken to isolate the lines manually.
The Station System Acceptance form (Reference 3) for this modification indicates that the system description had been updated.
Contrary to this indication, Compressed Air System Description III-10 (Reference 4) does not include valves HCV-438 8 and D on the list of valves equipped with instrument air accumulators.
The team noted that site acceptance of this modification was completed in May 1983 and that the Compressed Air System Description was most recently revised in April 1985.
l c.
Modification MR-FC-81-21 developed a component cooling water pressure low signal and added it to the control circuits for valves HCV-438 B and D, such that these valves remain open except when a containment isolation signal and a component cooling water pressure low signal are simultaneously present.
The Station System Acceptance form indicates that the system description had been updated.
Contrary to this indication, Component Cooling Water System Description I-7 (Reference 5) omits the low pressure signal and states that "CIAS closes containment isolation valves HCV-483A/B/C/0, thus isolating CCW flow to the reactor coolant pumps." The team noted that site acceptance for this modification was completed in riay 1983 and that the system description had not been updated since December 1981.
l The team determined that system descriptions are maintained by site l
engineering personnel, and during a site inspection the team was informed by site engineering personnel that the descriptions had numerous errors.
BASIS:
Omaha Public Power District's Quality Assurance Plan 5.1 (Reference 6) requires that those organizations participating in activities affecting safety l
shall be made aware of, and use, proper and current instructions, procedures, drawings, and engineering requircments for performing the activity.
Contrary A-15
to this requirement, design descriptions, available for use as design input, were incorrect or not updated followinc completion of modifications.
REFERENCES 1.
OPPD System Description III-4, Auxiliary Feedwater System, Rev. 5, August 16, 1984.
2.
OPPD Drawing 11405-M-252, Flow Diagram Steam, Rev. 33, June 21, 1984.
3.
OPPD Station System Acceptance form J for MR-FC-81-21B, CCW Isolation to RCP's, May 4, 1983.
4.
OPPD System Description III-10, Compressed Air, Rev. 5, April 10, 1985.
5.
OPPD System Description I-7, Component Cooling Water System, Rev. 3, December 3, 1981.
6.
OPPD Quality Assurance Plan 5.1, Control of Plant Design and Modifica-tions, Rev. 0.
A-16
U2.1-10 (Unresolved Item) Use of Fluorocarbon-Elastomer Material in High Radiation Environments DESCRIPTION:
During the team's examination of modification packages, the material compatibility with expected environments was reviewed for modification packages MR-FC-84-144 and MR-FC--83-158.
The first modification package involves the replacement of solenoid valves for YCV-1045 A and B.
The Final Design package (Reference 1) states that the existing solenoid valves are acceptable for the application but have Viton material as elastomer seals.
Viton is an E.I. duPont de Nemours trade name.
It is often described as a fluorocarbon elastomer and has the chemical designation as vinylidene fluoride and hexafluoro propylene.
The Final Design package indicated that Viton is not recommended for application in radiation areas; therefore, all solenoid valves containing this material are to be removed from service.
Likewise, the Engineering Evaluation and Assistance Request (Reference 2) indicates that the solenoid seals should be changed to avoid stocking Viton.
Omaha Public Power District's Technical Services organization concurred with the modification (Reference 3), indicating this modification will ensure no Viton parts are stored, since these parts are not to be installed in a radiation area.
Modification package MR-FC-83-158 is a normal modification to install air accumulators on the same valves YCV-1045 A and B, auxiliary feedwater turbine steam admission valves.
These instrument air accumulators were to be installed to permit the remote manual isolation of a steam generator in the event of a tube rupture with a concomitant loss of non-safety-related instrument air. This modification includes the installation of instrument air check valves to isolate the safety-related instrument air accumulators from the non-safety-related instrument air headers.
The team examined the procurement specifications for MR-FC-83-158 and determined that Viton was being used as a seating material in the safety-related instrument air check valve.
The procurement specification (Reference 4) for the safety-related instrument air check valves permits the use of Viton as a seat material.
The team noted that the original specification (Reference 5) specified Buna "N" as a seat material; however, the valve's supplier took exception to this seat material and stated in a letter (Reference 6) that Viton would be supplied instead.
Based upon this exception the specification was revised to include Viton as an acceptable seat material.
During the inspection, the licensee was unable to explain the disparity between the two modifications except to indicate that the radiation dose at the location of the solenoids and the safety-related check valves was sufficiently low that Viton would be an acceptable seating material.
The licensee pointed out that the procurement specification for the instrument air check valves was prepared based upon a specification previously used in another application.
The licensee stated that environmental conditions were not revised downward because the values specified were conservative.
Therefore, the specification identifies the radiation environment as 3.0 E6 rads even though the expected condition is apparently lower.
A-17
During the inspection, the team did not determine if Viton had been used in other instrument air applications or other safety-related applications.
The team requested a listing of all modifications which installed air accumulators.
In response to this request and at the end of the inspection, the licensee produced a short list of possible modifications apparently generated upon the recollection of various engineers.
Independently, the team identified a modification where air accumulators and instrument air check valves had been added; however, the team could not determine the seat material used in the check valves because the procurement specification was not included in the modification file (See Deficiency D2.2-4).
BASIS:
Criterion III of 10CFR50 Appendix B (Reference 7) requires that design control measures be applied to insure compatibility of materials.
Omaha Public Power District has committed to Regulatory Guide 1.64 (Reference 8) which endorses ANSI N45.2.11 (Reference 9).
The standard requires verifiers to confirm that the specified parts are suitable for the required application and that specified materials are compatible with the design environmental conditions to which the material will be exposed.
Contrary to these requirements, an unacceptable material may have been used in a high radiation environment.
REFERENCES 1.
OPPD Final Design for MR-FC-84-144, Replacement of the Solenoid Valves for YCV-1045A and YCV-1045B, Rev. O, March 20, 1985.
2.
OPPD Engineering Evaluation and Assistance Request No. FC-84-144, Upgrade of YCV-1045A Solenoid, August 23, 1984.
3.
OPPD Technical Services Review and Evaluation for Modification Request No. FC-84-144, Upgrade of YCV-1045A Solenoid, December 17, 1984.
4.
OPPD Instrument Air Check Valve Specification for MR No. FC-83-158, Rev.
1, August 15, 1985.
5.
OPPD Instrument Air Check Valve Specification for MR No. FC-83-158, Rev.
0, May 24, 1985.
i 6.
Omaha Valve & Fitting Company letter from S. Pendleton to H. Frazier (OPPD), August 13, 1985 i
7.
10 CFR 50 Appendix B, Quality Assurance Criteria for Nuclear Power Plants
(
and Fuel Reprocessing Plants 8.
Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2, June 1976.
9.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
A-18
r D2.2-1 (Deficiency) Incorrect Design Input In Calculation Associated With MR-FC-81-21B DESCRIPTION:
Modification MR-FC-81-218 is a completed modification which replaced fail close pneumatic actuators with actuators that fail open.
The replacement actuators were installed on valves HCV-438B and HCV-438D.
These valves are containment isolation valves located outside containment in the component cooling water supply and return lines associated with the reactor coolant pump lube oil coolers and seals.
This completed modification added instrument air accumulators to these valves to permit the valve operator to maintain the valves closed until operator action could be taken to manually close the valves.
Because this modification is similar to a modification planned for the 1985 outage (i.e., MR-FC-83-158), the team reviewed modification MR-FC-81-21B to determine if errors and discrepancies found during the review of modification MR-FC-83-158 were systematic.
The modification file contained a calculation sheet (Reference 1) which concluded that the air accumulator had sufficient volume.
This calculation was reviewed and the following discrepancies noted:
a.
The calculation states that the accumulator is a 20 pound propane tank and that the volume is 4423 cubic inches.
The source of this information is not referenced.
A 20 pound propane tank, typically, has a volume of approximately 1320 cubic inches.
The team believes that the volume of stored air used in the calculation is overestimated by 335 percent.
b.
The calculation assumes that the air pressure is at 100 psig.
The reference for this assumption and justification for its use is not documented.
The instrument air system pressure will range between 80 and 100 psig per the compressed air system description (Reference 2).
The assumption that the air accumulator is fully charged at maximum instrument air pressure is not conservative and inappropriate for an air accumulator sizing calculation.
c.
The calculation does not consider system leakage or the period of time that the valve must remain shut.
The valves operated by these accumulators are fail open containment isolation valves.
In the event of a need to close these valves, they would have to remain shut for the duration of the accident or until operator action is taken to manually shut the valve.
The implicit assumption of zero leakage is not l
conservative and unrealistic. The team noted that the air accumulator I
installation was not properly tested after modification (See Deficiency
(
D2.2-3) and that surveillance testing is not performed to demonstrate the capability of the Critical Quality Element (i.e., safety-related) portion I
of the instrument air system to close these valves and maintain them closed for a predetermined period of time without loss of function.
l 1
d.
The calculation sheet is not signed by a checker.
Instead reference is made to see a B-2-2 Form.
However, the B-2-2 form is not attached or included in the modification file.
BASIS:
Omaha Public Power District committed to Regulatory Guide 1.64 (Reference 3) which endorses ANSI N45.2.11 (Reference 4).
This standard A-19 i
I a
requires that calculations include defined objectives, identification of design inputs and their sources, and documentation of assumptions and identification of those assumptions which need confirmation at a later date.
Contrary to these requirements, the calculation contained incorrect and inappropriate assumptions without identification of their sources or justification for their use.
REFERENCES 1.
OPPD Generating Station Calculation Sheet for Modification File MR-FC-81-21B, Accumulator Tanks, March 26, 1983.
2.
OPPD System Description III-10, Compressed Air, Rev. 5, April 10,1985.
3.
Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2, June 1976.
4.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
A-20 L
D2.2-2 (Deficiency) Incomplete Consideration Of CQE And Seismic Class I Requirements For Portions of MR-FC-81-21B DESCRIPTION:
Modification MR-FC-81-21B is a completed modification which replaced fail close pneumatic actuators with actuators that fail open.
the replacement actuators were installed on valves HCV-438B and HCV-438D.
These valves are containment isolation valves located outside containment in the component cooling water supply and return lines associated with the reactor coolant pump lube oil coolers and seals. This completed modification added instrument air accumulators to these valves to permit the operator to maintain the valves closed until operator action could be taken locally to manually close the valves.
This modification was completed in 1983 and was similar to a modification planned for the 1985 outaga (i.e., MR-FC-83-158).
In USAR Appendix F, the component cooling water system is classified as a seismic Class I system.
In the Critical Quality Elements List, air accumulators and associated piping and valves that supply air to valves that must function following an accident are identified Critical Quality Elements based upon the classification and operating requirements of the valves that they supply.
HCV-438B and D are valves which are open following an accident and must have the capability to be closed throughout the course of the accident.
As a consequence, the air accumulators and associated piping and valves are seismic Class I and Critical Quality Elements because they must remain functional uaring and following an accident to shut HCV-438B and D.
The team reviewed the seismic qualification of components installed during this modification.
The team found that seismic requirements were not properly addressed in the modification package.
The following discrepancies were identified:
a.
Purchase Order No. 56600 (Reference 1) was issued to an engineering organization to confirm that the valve and operator assembly supplied by a manufacturer was seismically qualified without invoking the requirements of 10 CFR Part 50 Appendix B.
In addition, the purchase order did not invoke the requirements of 10 CFR Part 21 and was not identified as applicable to critical quality elements.
As a consequence, the engineering organization did not complete the computer analysis in accordance with their Quality Assurance Manual and identified this to Omaha Public Power District in an August 1983 la.tter (Reference 2).
Because the procurement was not considered to involve services for a Critical Quality Element, a Quality Assurance representative did not review the purchase order.
b.
The installation / test procedure (Reference 3) did not reference Fort Calhoun criteria (Reference 4) for routing and support of seismic instrument tubing.
c.
No calculation existed at the time the modification was completed to confirm that the as-constructed air accumulator, including base plate and Hilti bolts, was adequately sized to withstand expected seismic loadings.
A 1983 calculation (Reference 5) in the completed modification file does not address seismic considerations.
A subsequent generic analysis (Reference 6) performed in 1985 appears to A-21
confirm the configuration is adequate; however, confirmation is required to verify that the installed configuration is the same or is bounded by that analyzed.
During the site visit the team conversed with a site engineer regarding seismic requirements for the instrument air system.
The engineer, who stated he was responsible for installation of air accumulators, erroneously stated that no portion of the instrument air system was required following an accident, and therfore that there was no need for seismic installation.
BASIS:
Contrary to 10 CFR 50 Appendix B Criterion IV, the licensee did not assure that applicable regulatory requirements, design bases, and other requirements which are necessary to assure adequate quality are suitably included or referenced in documents for procurement of services.
Omaha Public Power District committed to Regulatory Guide 1.33 (Reference 7) which endorses ANSI N18.7 (Reference 8) for quality assurance program requirements for operating reactors.
This standard requires that each procedure contain instructions in the degree necessary for performing a required task by a qualified individual without direct supervision and that they contain appropriate references.
Contrary to these requirements tha procedure did not address the installation requirenients for seismic tubing.
Omaha Public Power District has committed to implement ANSI N45.2.11 (Reference 9) for design activities associated with modification of safety related structures, systems and components.
Contrary to the requirements of this standard, a design analysis was not performed in a planned, controlled, and correct manner.
REFERENCES 1.
OPPD Purchase Order No. 56600 to Stevenson & Associates, CERTIVALVE Computer Program Analysis for HCV-4388, May 11, 1983.
2.
Stevenson & Associates letter No. 83C2220 from W. Djordjevic to W. Weber (OPPD), CERTIVALVE Analysis of Fisher Valve HCV-438B for Ft. Calhoun Station, August 5, 1983.
3.
OPPD Revised Design Description Appendix 7.4 for MR-FC-81-21B, Installation Procedure for HCV-438B/D Air Accumulators, Rev. 2, March 26, 1983.
4.
Stone & Webster Report J.0. No. 13007.65, Guideline for the l
Installation of Tubing and Tubing Supports for Seismic Instrument Systems, March 1982.
5.
OPPD Generating Station Calculation Sheet for Modification File MR-FC-81-218, Accumulator Tanks, March 26, 1983.
6.
OPPD Calculation, Generic Air Accumulator Calculations, Rev. 1, j
September 10, 1985.
7.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Oper-ation), Rev. 2, February 1978.
8.
ANSI N18.7/ANS 3.2, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants, February 19, 1976.
9.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
A-22 m
D2.2-3 (Deficiency) Incomplete Installation / Testing Procedure Performed For MR-FC-81-21B DESCRIPTION:
Modification, MR-FC-81-21B is a completed modification which replaced fail close pneumatic actuators with actuators that fail open.
The replacement actuators were installed on valves HCV-438B and HCV-438D.
These valves are containment isolation valves located outside containment in the component cooling water supply and return lines associated with the reactor coolant pump lube oil coolers and seals.
This completed modification added instrument air accumulators to these valves to permit the valve operator to maintain the valves closed until operator action could be taken locally to manually close the valves.
This modification was completed in 1983 and was similar to a modification planned for the 1985 outage (i.e., MR-FC-83-158).
The team reviewed the post modification testing accomplished in view of the team's concerns expressed in Deficiency D2.1-7.
The post-modification test procedure (Reference 1) did not require the use of the pressurized volume of the accumulator to shut the valves.
The installation and test procedure closed HCV-438B and D, then isolated air from the instrument air header by closing valves IA-174 and IA-175.
In this configuration, only a static test was conducted.
The test procedure did not require the use of the pressurized volume of the accumulator to shut the valves.
The acceptance criteria was to ensure that the valves remained shut for twenty minutes; however, the team found no documented basis that twenty minutes was a sufficient period of time to identify the need to manually close these valves and to physically have a plant operator perform the required action locally at the valves.
BASIS:
Omaha Public Power District has committed to Regulatory Guide 1.33 (Reference 2) which endorses ANSI N18.7 (Reference 3).
This standard requires that modifications which affect functioning of safety-related structures, systems, or components be inspected and tested to confirm that the modifications or changes reasonably produce expected results and the change does not reduce safety of operations.
These test procedures are to include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.
Contrary to these requirements, the test procedure would not have confirmed that the l
modificatio~n produced expected results and did not have acceptance criteria l
for acceptable air leakage.
i l
REFERENCES l
1.
OPPD Setpoint/ Procedure Change No. 10320 for EEAR FC-81-21B/SRDC0 l
83-27.
Appendix to EEAR FC-81-21B/SRDC0 83-27 Test Procedure for Accumulators, March 28, 1983.
2.
Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Rev. 2, February 1978.
3.
ANSI N18.7/ANS 3.2, Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants, February 19, 1976.
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02.2-4 (Observation) Incomplete Modification File for a Completed Modification DESCRIPTION:
Modification MR-FC-81-21 is a completed modification which replaced fail close pneumatic actuators with actuators that fail open.
The replacement actuators were installed on valves HCV-438B and HCV-4380.
These valves are containment isolation valves located outside containment in the component cooling water supply and return lines associated with the reactor coolant pump lube oil coolers and seals.
This completed modification added instrument air accumulators to those valves to permit the valve operator to maintain the valves closed until operator action could be taken to manually close the valves.
Because this modification is similar to a modification planned for the 1985 outage (i.e., MR-FC-83-158), the team reviewed modification MR-FC-81-21B to determine if errors and discrepancies found during the review of modification MR-FC-83-158 were systematic.
In reviewing this completed modification, the team identified information missing from the modification file as follows:
a.
Although a Generating Station Engineering Calculation Sheet (Reference 1) was included in the modification file, there was no record of a third party review or checking of the calculation.
The team did not find a verification checklist demonstrating a third party review or a completed Form B-2-2 documenting a checker's review.
b.
Although instrument air check valves were procured, no indication exists of a procurement specification or of a third party verification.
Improved implementation of the licensee's document control methods should preclude incomplete files and enhance the design control process.
REFERENCES 1.
OPPD Generating Station Calculation Sheet from Modification File MR-FC-81-218, Accumulator Tanks, March 26, 1983.
2.
Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2, June 1976.
3.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
4.
GSE Administrative Procedure A-9, Document Control, Revised August 1983.
5.
GSE Administrative Procedure A-2, Modification Request Development, Revised January 1984.
6, GSE Design Procedure B-11, Design Verifications, Revised April 1982.
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D2.2-5 (Deficiency) Incorrect Information On Instrument Air Diagram DESCRIPTION:
The team reviewed the portions of the instrument air system while evaluating post-modification testing requirements for planned modification MR-FC-83-158 and completed modification MR-FC-81-218.
Instrument air header isolation valves, IA-175 and IA-176, were used during the installation and testing of modification MR-FC-81-21B.
However, these valves do not appear on Omaha Public Power District drawing 11405-M-264 (Reference 1).
It appears that these valves were overlooked when preparing the drawing or incorrectly deleted.
During a field inspection the team confirmed that the valves are installed in the plant.
BASIS:
Omaha Public Power District has committed to Regulatory Guide 1.64 (Reference 2) which endorses ANSI N45.2.11 (Reference 3).
This standard requires that documents, including changes, be reviewed for adequacy and approved for release by authorized personnel.
Contrary to this requirement, a document was released which did not depict the as-installed piping / valving arrangement in the plant.
REFERENCES 1.
OPPD Drawing 11405-M-264, Instrument Air Diagram Riser Details, Rev. 4, June 27, 1984.
2.
Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2,~ June 1976.
3.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
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D2.2-6 (Deficiency) 10CFR 50.59 Safety Evaluation Based Upon An Incorrect Assumption and Analysis Methodology DESCRIPTION:
Modification MR-FC-81-21B is a completed modification which replaced fail close pneumatic actuators with actuators that fail open.
The replacement actuators were installed on valves HCV-438B and HCV-438D.
These valves are containment isolation valves located outside containment in the component cooling water supply and return lines associated with the reactor coolant pump lube oil coolers and seals.
This completed modification added instrument air accumulators to these valves to permit the valve operator to maintain the valves closed until operator action could be taken locally to manually close the valves.
In addition, the modification added a component cooling water pressure low signal in series with a containment isolation actuation signal such that the presence of both signals is necessary to close the valves.
Asaresuftofthismodification,thepost-LOCAheatloadwas increased by 3.15 x 10 BTU / hour which corresponds to the heat load from the reactor coolant pump seal and lube oil coolers.
A safety evaluation (Reference 1) was included in the Final Design Description (Reference 2) for the modification.
This evaluation cor.cluded that (a) the modification would not increase the probability of an occurrence or the consequences of an accident from the analysis previously done in Volume 4, Section 9.7 of the Fort Calhoun USAR, (b) the modification would not create the possibility of an accident or malfunction other than those analyzed in Volume 4, Section 9.7 of the Fort Calhoun USAR, and (c) the modification would not reduce the margin of safety as defined in the basis for technical specifications since this is not a basis for a technical specification.
This modification was completed and site accepted (Reference 3) in May of 1983.
Based upon the team's review of this safety analysis the following conclusions were made:
o The safety analysis performed by an Omaha Public Power District Design Engineer did not refer to original design calculations. The lack of original design analyses or their unavailability did not result in the performance of new calculations, instead the Design Engineer used a qualitative argument based upon USAR statements.
o The qualitative argument used by the Omaha Public Power District Design Engineer does not reflect a correct understanding of the heat transfer phenomenon between heat removal systems. Specifically, the team found that the qualitative argument implicitly assumed that the designed heat removal capacities of equipment coolers and heat exchangers are independent of each other and therefore can be added and subtracted to determine heat removal capacity between systems.
o The safety evaluation contains an unsubstantiated and inappropriate assumption concerning operator action to secure heat loads under certain accident conditions.
o The basis of technical specification 2.4 contains incorrect informa-l tion concerning the heat removal capacity of the component cooling water l
heat exchangers.
(
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although the Design Engineer stated that the margin of safety as defined in the basis for a technical specification was not reduced, it appears that he recognized that the basis of technical specification 2.4 contained information which was incorrect and required revision regardless of the proposed mcd fication.
This is evident by comments made in the safety analysis of the Final Design Description.
The basis of technical specification states that thiee component cooling heag exchangers have sufficient capacity (with ample reserve) to remove 420 x 10 BTV/ hour following a loss-of coolant accident.
However,thesafetyanalygisinthemodificationfileindicatesthattheheat removal value of 420 x 10 BTV/hourcorrespondstoghecapacityofthe containment air coolers (two units rated at 70 x 10 BTU / hour / unit) and 6
cooler / filters (two units rated at 140 x 10 BTU / hour / unit), not the component cooling water heat exchangers.
The safety evaluation states that removalcapacityofthecomponentcoolingwatersystemis402x10{heheat BTU / hour assuming three of four heat exchangers and two of three pumps are a/ailable.
6 To address the addition of 3.15 x 10 BTU / hour from the reactor coolant pump seal and lube oil coolers and the apparent existing error in the basis of the technical specification, the design engineer presented the following rationale forconcgudingnosafetyimpact.
First, he noted that the USAR states that 280 x 10 BTU / hour of heat removal capacity is assumed in the containment pre:sure and temperature analysis and that both the containment spray system and the containment air cooling system are each designed to remove heat in excess of this value during post-LOCA conditions.
Second, he states that the containment spray system is independent of the containment air cooler system (i.e., as long as either system is available the containment heat removal function will be satisfied).
Third, he eliminates from further consideration heat loads from the containment spray system to the component cooling water system by noting that component cooling water is only supplied to the shutdown cooling heat exchangers to remove containment spray system heat loads upon receipt of a recirculation actuation signal which occurs later in the accident, when air cooling loads are significantly reduced.
Based upon the foregoing, the design engineer appears to have concluded that the post-LOCA 6
heat load seen by the component cooling water system can be as high as 425 x 10 BTU / hour immediately following an agcident if all containment air cooling 6
coils perform as designed (425 x 10 E6 BTV/ hour based up n the sum of 420 x 10 6
BTU /hourfromcontainmentaircoolingcoils,3.g5x10 BTU / hour from the reactor coolantpumpsealgndlubeoilcoolers,0.3010 BTU / hour from charging pump coolers, 1.05 x 10 BTg/hourfromthesafetyinjectionandcontainmentspraypump coolers, and 0.30 x 10 BTU / hour from the control room air conditioning).
Because this value exceeds the designed heat removal capacity of the component cooling water heat exchangers, the design engineer assumed in the safety evaluation that if all containment air cooling system units operated as 6
designed that the operator would select one cooling unit rated at 70 g 10 BTU / hour and isolate it to reduce the post-LOCA heat load to 355 x 10 BTU / hour.
This value is then within the heat removal capacity of the component cooling water system.
Based upon the documentation in the modification file and the lack of any reference to design analysis in the safety analysis, it appears that no comparison was made to original design calculations.
The team determined that design calculations are not controlled by Omaha Public Power District as living design documents but are filed when performed with the modification package.
The team was informed that original calculations performed by the architect-engineer during construction may or may not be available because the A-27
original design was performed in the late 1960's and that the information that is available is in storage.
The team found that some original architect-engineering information was located in 'i N within Generating Station Engineering's document control area and some information was located outside the building in commercial storage.
However, the team determined that these files were not organized into a workable source of original design information for assessing the original design basis.
As a consequence, the team found that this information was not generally used by design engineers working on modification packages.
It appears that the Omaha Public Power Design Engineer resorted to using information contained in the USAR without confirming its accuracy and also used qualitative judgements to conclude that the modification was adequate.
To implement this safety evaluation, the Design Engineer prepared proposed revisions to the basis of technical specification 2.4 and USAR sections 1.4, 6.3, 6.4, and 9.7.
The team determined that all of the USAR sections were revised in accordance with the Design Engineer's incorrect safety analysis.
In spite of the Design Engineer's assumption of operator action, the emergency operating procedure for a LOCA (Reference 4) was not revised.
The emergency procedure does not instruct or caution the operator to secure one containment air cooling unit if all cooling units start as designed and off-site power is available.
As a consequence, the USAR does not agree with the emergency operating procedure.
A Document Update Checklist (Reference 5) completed by the Design Engineer indicates that operating instructions and emergency procedures do not require revision even though his safety evaluation and USAR revisions require such action.
The team found that controlled copies of the Technical Specifications in the control room and in Generating Station Engineering's reference library still contained an unrevised basis for technical specification 2.4.
Specifically, theheatremovalcapagityofthecomponentcoolinggaterheatexchangersis described as 420 x 10 BTU / hour instead of 402 x 10 BTU / hour.
BASIS: Omaha Public Power District has committed to Regulatory Guide 1.64 (Reference 6) which endorse ANSI N45.2.11 (Reference 7).
This standard requires that design changes be reviewed and approved by the same groups or organizations which reviewed and approved the original design documents. When an organization which originally was responsible for approving a particular design document is no longer available, the ANSI N45.2.11 Standard states that the plant owner shall designate a new responsible design organization which may be the owner's own engineering organization and that the designated organization shall have access to pertinent background information, have demonstrated competence in the specific design area of interest and have an adequate understanding of the requirements and intent of the original design.
Although the Omaha Public Power District's engineering organization can be designated as the new responsible organization, it is required to have an adequate understanding of the requirements and intent of the original design.
Contrary to these requirements, Omaha Public Power District's Genh ating Station Engineering organization did not have access to original design analyses nor did not prepare comparable design analyses in the absence of such design analyses. Instead, a qualitative argument was employed based upon an 4
incorrect understanding of the heat transfer phenomenon between heat removal A-28
j systems.
10CFR 50.59 permits licensees to make changes, conduct testing or experiments as described in the safety analysis report without Commission approval, unless such action involves a change in the technical specifications or an unreviewed safety question.
An unresolved safety question is defined, in part, to occur if the margin of safety as defined in the basis for any technical specifica-tion is reduced.
Contrary to this requirement the licensee did not identify that the basis of a technical specification was incorrect.
REFERENCES 1.
OPPD Safety Analysis, MR-FC-81-21B Component Cooling Water Isolation to Reactor Coolant Pump Seals Appendix 7.3 Safety Analysis, Rev. 0, August 30, 1982.
2.
OPPD Revised Final Design Description, MR-FC-81-21B Component Cooling Water Isolation to Reactor Coolant Pump Seals, Rev. 1, December 6, 1982.
3.
OPPD Station System Acceptance, EEAR/MR-FC-81-21B CCW Isolation to RCPs, May 5, 1983.
4.
OPPD Emergency Procedure EP-5, Loss of Coolant Accident, Rev. 24, April 4, 1985.
5.
OPPD Document Update Checklist for SRDC0 81-239, Completed between November 17 and November 18, 1981.
6.
Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2, June 1976.
7.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants, 1974.
J A-29
D3.1-1 (Deficiency) Plant Design Specifications DESCRIPTION:
Section "H" of Omaha Public Power District Contract No. 763 contains 46 design specifications which goverred the analysis, design, fabrication and testing of balance-of plant piping systems and equipment procedure for Unit No. 1, Fort Calhoun Station.
The design specifications contained in Omaha Public Power District Contract No. 763 do not constitute a controlled design document.
These specifications have not been revisau or distributed to the design staff.
The corresponding specifications issued by the architect-engineer, Gibbs, Hill, Durham and Richardson, which derived from the specifications detailed in Contract No.
763; have also not been revised or distributed to the engineering staff in a controlled manner.
These latter specifications were design input for piping at the plant.
As an example, Omaha Public Power District's Piping and Instrumentation Diagram 11405-MECK-1 notes that:
"All piping shall be in accordance with the requirements of the latest issue of Gibbs & Hill Piping Specification H-1."
However, Omaha Public Power District could not access this document during the inspection.
In the absence of the design specifications issued by the architect-engineer, the design specifications contained in Contract No. 763 appear to be used as the defining design document for much of the plant piping and equipment.
BASIS:
The Omaha Public Power District Quality Assurance Manual (which implements Omaha Public Power District commitments to ANSI N45.2.11) requires that:
(1) " Applicable design inputs, such as design bases, regulatory requirements codes and standards, shall be identified, documented and their selection reviewed and approved.
Changes from specified design inputs, including the reasons for the changes, shall be identified, approved, documented and controlled," (Chapter 5.1 of Plant Design and Modifications, Section 4.2, Design Inputs, Subsection 4.2.1.), and:
(2) " Methods shall provide for relating the final design back to the source of design input.
This traceability shall be documented."
(Chapter 5.1, Section 4.2, Subsection 4.3.3.)
Contrary to these requirements, plant design specifications are not being controlled.
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l t
l l
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i
D3.1.2 (Deficiency) Design Temperatures for Safety-Related Piping DESCRIPTION:
In order to qualify a piping system, either by explicit or generic analysis, the imposed loads, which include consideration of operating and accident temperature, must be defined.
In 1980, Omaha Public Power District provided temperature data to Gilbert / Commonwealth to reanalyze a number of safety-related piping systems in the Ft. Calhoun plant in response to Bulletin 79-14.
Generating Station Engineering (GSE) verbally requested that Technical Services (TS) collate the operating and accident temperatures for the safety-related piping in Ft.
Calhoun.
Technical Services subsequently transmitted this data to Generating Station Engineering on a marked-up set of piping and instrumentation diagrams.
Technical Services compiled this temperature data from the FSAR, and from analytical and operating data.
Omaha Public Power District subsequently transmitted the set of marked-up piping and instrumentation diagrams to Gilbert / Commonwealth for use in their reanalysis. The marked-up set of piping and instrumentation diagrams is not a controlled document.
The original analysis temperatures which the architect-engineer (Gibbs, Hill, Durham and Richardson) originally used to perform piping analysis was not accessed in preparing the transmittal of information to Gilbert / Commonwealth.
Neither the licensee nor the team could determine if the operating and accident temperatures which Gilbert / Commonwealth used to reanalyze a number of safety-related piping systems were consistent with the temperature data originally used to qualify these piping systems.
The operating and accident temperatures detailed on the marked-up piping and instrumentation diagrams were used for all reanalysis work performed by Gilbert / Commonwealth, and may have been used subsequently by Omaha Public Power District for modifications to the installed piping.
BASIS: The transmittal and use of uncontrolled temperature data is contrary to the following requirements of the Omaha Public Power District Quality Assurance Manual:
(1) Chapter 3.1, Document Control, Section 4.0, Requirements and Controls, Subsection 4.1.1, which notes, in part, that:
"The preparation, issue and change of documents that specify quality requirements or prescribe activities affecting quality shall be controlled to assure that correct documents are 4
being employed";
(2) Chapter 5.1, Control of Plant Design and Modifications, Section 4.2, Design Inputs, Subsection 4.2.1, which notes that:
" Applicable design inputs, such as design bases, regulatory requirements, codes and star.dards, shall be identified, documented and their selection reviewed and apprbved.
Changes from specified design inputs, including the reasons for the changes, shall be identified, approved, documented and controlled";
(3) Chapter 5.1, Section 4.3, Design Process, Subsection 4.3.3, which notes that:
" Methods shall provide for relating the final design back to the source of design input.
This traceability shall be documented";
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(4) Chapter 5.1, Section 4.4, Interface Control, Subsection 4.4.4, which notes that:
" Procedures shall be established to control the flow of design information between Divisions / Departments.
Design basis information transmitted from one Division / Department to another, shall be documented and controlled.
Transmittals shall identify the status of the design basis information or documents provided and, where necessary, identify incomplete items which require further evaluation, review, or approval.
Where it is necessary to initially transmit design basis information orally or by other informal means, the transmittal shall be confirmed by a controlled document,"
and; (5) Cnapter 5.2, Calculational Analysis, Section 4.0, Requirements and Contrcls, Subsection 4.1.1, which notes, in part, that:
" References and calculation inputs shall be identified, and shall be traceable to their source documents to permit subsequent verification."
=
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i U3.1-3 (Unresolved Item) Small Bore Pipe Support Spacing DESCRIPTION:
Piping two inches and smaller was field routed for Unit No. 1, Fort Calhoun Station.
Peter Kiewit Sons' Co., the contractor performing the field routing, based restraint spacing and type on the technical criteria detailed in " Recommended Procedure for the Support & Seismic Restraint of Piping 2 Inch and Smaller." This procedure was developed by the contractor on the basis of technical data developed by the architect-engineer, Gibbs, Hill, Durham ar.d Richardson, Inc. The contractor's support spacing criteria differ from the seismic criteria detailed in the USAR for piping penetrating the containment.
As noted in the procedure under the heading entitled, SEISMIC DESIGN CRITERIA:
"The calculation method used in determining seismic forces is based on the premise that the piping as restrained falls within the rigid range which precludes the possibility of the piping going into resonance with the imposed and/or building response frequency, thereby allowing the use of conservative seismic acceleration design factors.
The minimum natural frequency as designated by the engineers is 20 cycles per second in the horizontal direction and 60 cycles per second in the vertical direction for the Intake Structure, and 6 cps horizontal, 18 cps vertical for the Auxiliary Building and Containment."
USAR Appendix F, subsection F.2.2.2, notes that:
"The first step in seismic analysis of piping was to position seismic restraints closely enough to ensure that the natural frequency of piping in the auxiliary building and containment building was 6 hertz horizontally and 18 hertz in the vertical direction."
However, USAR subsection F.2.5 specifies a more stringent criterion of 12 (rather than 6) hertz in the horizontal direction:
"Therefore, for those piping runs which penetrate the containment shell or are otherwise connected to it, the spacing of restraints was such as to assure a lowest dominant natural frequency of 12 Hz horizontally and 18 Hz vertically for the pipe run up to the first point of full fixity."
BASIS:
Based on the available documentation small-bore Class I pipe connected to or penetratino the containment may not meet USAR seismic criteria, considering the discrepancy between the contractor's support spacing criteria and the seismic criteria detailed in the USAR for small-bore (Class I) pipe penetrating or connected to the containment shell.
No additional field routing procedures or analyses were available which address increased horizontal rigidity for these piping systems.
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03.1-4 (Observation) Seismic Qualification Of Valves Installed In Class I Piping Systems.
DESCRIPTION:
USAR Appendix F categorizes structures, piping systems and equipment either as Class I or Class II (a plant-unique designation, not an ASME classification) for purposes of seismic qualificat. ion at Fort Calhoun Station.
The team examined the design process relating to valves to ascertain if seismic considerations had been incorporated. Seismic qualification of valves installed in Class I piping systems could not be determined by the team.
As noted on page 1.4 of the Critical Quality Element List (Reference 1):
"Until the present ASME Section III component code was developed, items such as pumps and valves were not specifically covered by a nuclear code," and:
"In order to apply codes which were, in many cases, written for piping only, the architectural engineering firm (Gibbs, Hill, Durham and Richardson) and Omaha Public Power District developed the specifications for pumps and valves.
The local designations are Class A (safety class) and Class B (non-safety class).
The specifications for thest : lasses can be obtained by referring to the original contract documents." Tbc team examined the design specifications contained in Omaha Public Power disti.ct Contract 763, the original contract documents used to procure valves for Fort Calhoun Station (References 2-6),
excluding those supplied by the NSSS.
No seismic criteria are detailed in these specifications. Valves for the Ft. Calhoun plant were constructed in accordance with piping codes ASA B31.1 and USAS B31.1.
Subsection F.2.2.1 of the USAR lists the following methods of analysis which were applied to Class I structures, systems, and equipment:
a.
The natural frequer.cy of vibration of the structure or component was deternined.
b.
The response acceleration of the component to the seismic motion was-taken from the response spectrum curve at the appropriate natural freque ncy and damping factor.
c.
Stresses resulting from the combined influence of normal loads and the additional load from the design earthquake were calculated and checked against the limits imposed by the design standard.
d.
Stresses and deflections resulting from the combined influence of normal loads and the additional loads from the maximum hypothetical earthquake were calculated and checked to verify that deflections would not produce rupture.
The NRC has already identified that for older plants, documentation is not always available to establish seismic qualification of components.
A program is in place to examine this issue on some older plants (post Systematic Evaluation Program plants, including Fort Calhoun Station).
This program for resolution of Unresolved Safety Issue A-46 (Reference 7) will include a review of seismic capability of valves and valve operators.
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1 1
REFERENCES 1.
Omaha Public Power District, Fort Calhoun Station - Unit No. 1 Critical Quality Elements (C.Q.E.) List, Rev. 2, Issued May 24, 1985.
2.
OPPD Contract No. 763, Technical Specification No. 10, Safety and Relief Valves.
3.
OPPD Contract No. 763, Technical Specification No. 11, Manual Globe, Gate and Self-Actuated Check Valves.
4.
OPPD Contract No. 763, Technical Specification No. 12, Manual Ball, Butterfly and Saunders Patent Valves.
5.
OPPD Contract No. 763, Technical Specification No. 13, Motor Operated Valves.
6.
OPPD Contract No. 763, Technical Specification No. 14, Air Operated Valves.
7.
NUREG -1030 (Draft), Seismic Qualification of Equipment in Operating Nuclear Power Plants and Regulatory Analysis for Proposed Resolution of Unresolved Safety Issue A-46, published September 4, 1985 (FR85-21054).
I A-35
U3.2-1 (Unresolved Item) MR-FC-84-61 Design Input Source and Use.
DESCRIPTION:
The team reviewed modification request FC-84-61, which installed unions to facilitate the periodic removal of safety injection relief valves SI 209, 213, 217 and 221 for setpoint testing.
USAR Appendix F defines the safety injection system as a Class I system.
The Final Design for MR-FC-84-61 (Reference 1) does not reference:
(1) The source of analysis temperatures and pressures used as calculation input for the portion of the safety injection system to be modified; (2) The governing load combinations detailed ir. USAR Appendix F, Table F-1; (3) The vendor drawing for the safety injection tank relief valves; (4) The design basis for the seismic qualification of the safety injection system, and; (5) Existing support locations and types for the portion of the safety injection system to be modified.
With respect to item (1), only the rated pressure at maximum operating temperature is specified for the safety injection tank / relief valve system; the pressure is specified as 265 psig in Section 6.0 of the Final Design, and as 275 psig in Secticn 7.0 of the Final Design. With respect to items 2-5, the team found that the engineer did not analyze seismic effects and did not document his judgement that such analysis was not required.
BASIS: The Omaha Public Power District Quality Assurance Manual which implements the licensee's commitments to ANSI N45.2.11, requires that:
(1) " Applicable design inputs, such as design bases, regulatory requirements, codes and standards, shall be identified, documented and their selection reviewed and approved", (Chapter 5.1, Control of Plant Design and Modifications, Section 4.2, Design Inputs, Subsection 4.2.1);
(2) " Analyses shall be sufficiently detailed as to purpose, method, assumption, design input, references and units such that a person technically qualified in the subject can review and understand the analyses and verify the adequacy of the results without recourse to the originator," (Chapter 5.1, Section 4.3, Subsection 4.3.5).
Contrary to these requirements, the licensee has not identified the source of design input and sufficiently documented analyses including engineering judgements.
REFERENCES 1.
OPPD Final Design for MR-FC-84-61, Form GSE-B-2-2, Revision 1, dated January 15, 1985.
2.
Peter Kiewit Sons' Co. Contract 763, Group I & Group II Piping Systems Recommended Procedure for the Support & Seismic Restraint of Piping 2-Inch and Smaller.
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D3.2-2 (Deficiency) MR-FC-83-158 Installation Procedure DESCRIPTION:
Support design for tubing and small-bore piping, which addresses the governing seismic criteria, is normally performed on a generic basis.
Support spacing is then accomplished in accordance with generic design guidelines, instead of a detailed physical or isometric drawing. The installation procedure for modification request FC-83-158 does not address support spacing requirements for tubing.
Modification request FC-83-158 provides air accumulators with check valves for valves YCV 1045 A and B.
These valves are on the steam feed to the turbine auxiliary feedwater pump FW-10, and are fail open valves. The Final Design provides a sketch which schematically locates the new tubing, valves and air accumulator with respect to the existing air set and root valve. However, the installation procedure does not reference a generic support spacing procedure.
The team notes that Stone & Webster prepared such a guideline for Omaha Public Power District in 1982 (Reference 1), which provides generic routing and support criteria for seismic instrument piping. The team also notes that the radial location of the Hilti bolts which restrain the air accumulator was not defined in Section 6.3 of the installation procedure.
Subsequent to the preparation of the installation procedure Omaha Public Power District performed a calculation which seismically qualifies the air accumulator support configuration (Reference 2). That calculation specifies a 9-inch radial location of the Hilti bolts with respect to the centerline of the air accumulator.
BASIS:
The licensee committed to ANSI N18.7 (Reference 3), which requires that each procedure contain instructions to the degree necessary for performing a required task by a qualified individual without direct supervision, and that the procedure contain appropriate references. Contrary to this require-ment, the procedure did not address the installation requirements for seismic tubing.
REFERENCES 1.
Stone & Wet, ster guideline," Guideline for the Installation of Tubing and Tubing Su ports for Seismic Instrument Systems," J. O. No. 13007.65, dated March 3, 1982.
2.
OPPD Calculation, " Generic Air Accumulators using Propane Tanks Built to 00T Spec. 4BA-240," Rev. O, 6 pp., dated August 15, 1985; Rev. IR, 1 page, dated September 11, 1985.
3.
ANSI N18.7/ANS 3.2, " Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants", February 19, 1976.
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D3.2-3 (Deficiency) MR-FC-84-162 Calculation DESCRIPTION:
A calculation prepared to qualify a modification to an existing ventilation duct support must consider the specified design and operating conditions, as well as the applicable seismic provisions of USAR Appendix F.
The team reviewed modification request FC-84-162, which redesigns two containment ventilation duct supports to improve personnel and equipment access. The containment heating, ventilation, air conditioning ductwork is categorized as Class I equipment.
Team review of the calculations filed with the modification indicates that:
(1) Thermal loads were not considered.
Specification No. 21 (Reference 1) specifies a design basis accident temperature of 288 degrees F.
(2) The natural frequency of the duct is computed on the basis of linear beam theory, which is unconservative for the intent of this calculation which is to establish that the duct has a fundamental frequency in the rigid range; i.e., greater than 33 Hz.
(3) The 4 in. x 4 in. x 1/4 in. horizontal support angle is sized on the basis of a bending moment which is half the magnitude of the critical bending moment in the angle (4954 vs. 10710 in-lb).
(4) The combination of vertical seismic and horizontal seismic loads in the transverse direction of the horizontal angle was not considered.
There are no supporting calculations which justify this assumption.
(5) The new supplementary steel is to be painted; however, Specification No. 20 (Reference 2) requires that supplementary steel be galvanized.
There was no documentation addressing this deviation from the specification.
BASIS: The Omaha Public Power District Quality Assurance Manual which implements the licensee's commitment to ANSI N45.2.11 requires that:
(1) " Applicable design inputs, such as design bases, regulatory requirements, codes and standards, shall be identified, documented and their selection reviewed and approved", (Chapter 5.1, Control of Plant Design and Modifications, Section 4.2, 0. Design Inputs, Subsection 4.2.1).
(2) " Methods shall provide for relating the final design back to the source of design input.
This traceability shall be documented",
(Chapter 5.1, Section 4.3, Design Process, Subsection 4.3.3).
Contrary to its commitments, the licensee did not control design inputs nor relate the final design back to the source of design inputs.
REFERENCES 1.
OPPD Contract No. 763, Section "H", Technical Specification No. 21, Reactor Containment Ventilation, Air Cooling and Filtering Equipment.
2.
OPPD Contract No. 763, Section "H", Technical Specification No. 20, Heating, Ventilating and Air Conditioning Equipment.
A-38
D3.2-4 (Deficiency) Junction Box Supports DESCRIPTION:
The team inspected valve YCV-1045B, which is on the steam feed to turbine auxiliary feedwater pump FW-10, during a plant walkdown conducted on September 20, 1985.
The team noted that junction box JB-432A, which supplies power to the operator for valve YCV-10458, is restrained by a pair of unistrut supports, which are in turn supported by conduits EB-4943, EB-9494 and EB-9127.
The team questioned the support configuration for this junction box, in that unistrut supports are normally used to support conduit and conduit are generally not used as supporting members. Omaha Public Power District could not produce a seismic analysis which qualifies this configuration.
BASIS:
USAR Appendix F requires that appurtenances to Class I systems be seismically qualified to the Class I standards detailed therein. As noted in Subsection F.1.3 of USAR Appendix F:
"All supports associated with Class I equipment are to be designed to Class I standards, i.e., in accordance with the seismic criteria detailed in USAR Appendix F".
Contrary to USAR commitments, the licensee has not demonstrated seismic qualifications of the above equipment.
A-39
03.2-5 (Observation) Containment Pressure Switch Seismic Qualification DESCRIPTION:
Modification request FC-83-83 was prepared to evaluate alternate replacement switches for the containment pressure switches which feed the engineering safeguards system logic matrices.
The team reviewed the seismic qualification of SOR pressure switches A-D/PC-742-1 and A-D/PC-742-2 (eight pieces), and the seismic qualification of the associated switch supports and Hoffman boxes, with the exception of the seismic qualification of the supporting instrument rack.
The team found the seismic qualification tests of tne pressure switches performed by ACTON on behalf of SOR to be acceptable (Reference 1).
The Omaha Public Power District calculation performed to qualify the WT2x6.5 support for the pressure switch duas not reference the drawing for the pressure switch, preventing confirmation of the switch dimensions and weight used in the analyses (Reference 2).
In addition, the Hoffman box shown on the Omaha Public Power District arrangement drawing (Reference 3) was not identified in the Omaha Public Power District calculation and was not included in the analysis:
The team believes that a more thorough analysis for this modification would provide additional assurance of the equipment's seismic qualification.
REFERENCES 1.
ACTON Report No. 17344-82N-D entitled, " Qualified Pressure Switches for Nuclear Service / Test Report for Nuclear Qualification," dated February 4, 1983.
2.
SOR Drawing, entitled " Dimension Drawing 12N6-BB4-NX-CIA-JJTTX6, Drawing No. 8215-783, Rev. 1," dated November 29, 1984.
3.
OPPD Drawing entitled, " Pressure Switch Mounting Arrangement, Drawing No.
B-4091, Rev. 0", dated May 21, 1985.
l A-40
D3.2-6 (Deficiency) Steam Generator Nozzle Dams DESCRIPTION:
Omaha Public Power District contracted for the fabrication of removable pipe plugs (dams) for the hot and cold leg pipes of the steam generator (MR-FC-84-92) to enable refueling to proceed concurrently with primary head work such as eddy current examinations.
As such, these dams are the boundary of the reactor coolant system during such refueling operations.
The steam generator nozzle dams are designated as critical quality elements on Purchase Order No. 7234, and are, therefore, subject to the seismic provisions detailed in USAR Appendix F for Class I equipment.
However, Omaha Public Power District Contract No. 1453 to Nuclear Energy Services (NES), the nozzle dam vendor, did not specify any seismic criteria, and NES did not perform a seismic analysis.
BASIS:
The Omaha Public Power District failed to ensure that the steam generator nozzle dams were qualified to the governing seismic provisions.
USAR Appendix F, Section F.1.3, lists the reactor coolant system as a Class I System.
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A-41
D3.2-7 (Deficiency) YCV 1045B Valve Restraint DESCRIPTION:
During the inspection, the team toured the plant to examine various equipment scheduled for modification during the upcoming outage.
The team examined auxiliary feedwater steam feed valve YCV-1045 B, an air operated valve scheduled to have an accumulator added to ensure the valve operator's ability to close the valve following a steam generator tube rupture with concomitant loss of the non-safety instrument air system.
The team noted that the valve's operator was questionably restrained by a thin rod attached to a stair post, and therefore examined the seismic qualification of the piping subsystem containing YCV-1045 B.
In response to NRC Generic Letter No. 81-14, " Seismic Qualification of Auxiliary Feedwater Systems," (Reference 3), Omaha Public Power District engaged Gilbert / Commonwealth to perform an evaluation of the auxiliary feedwater system at Fort Calhoun Station.
Omaha Public Power District actions taken to bring the system into compliance with IE Bulletin No. 81-14 are contained in Omaha Public Power District Modification Request No. FC-81-127.
MR-FC-81-127 summarizes the four major seismic deficiencies identified by Gilbert / Commonwealth.
One of these, Item 2 of Form B states:
" Valve Operators on Small Bore Piping.
The current operator supports were found to be unstable.
Modification work will involve removing the existing support rods and replacing them with a more stable support by the end of 1981."
Gilbert / Commonwealth specifically noted that the valve operator for valve YCV-1045B is unstable in the transverse direction, and recommended that the existing rod restraint be replaced with a strut in the transverse direction (Reference 1, attachment 2).
Gilbert / Commonwealth recommended the addition of a number of supports for the steam drive and condensate portions of the auxiliary feedwater piping associated with pump FW-10.
Gilbert / Commonwealth also recommended that a detailed stress analysis be performed to assure that the additional supports do not have a detrimental thermal impact on the system (Reference 1, attachment 2).
Omaha Public Power District elected to perform the required analysis, using computer codes TPIPE and NUPIPE.
The licensee's response to Generic Letter 81-14 (Reference 1) identified the four major seismic deficiencies and included as attachments the Gilbert /
Commonwealth Inspection Evaluation Report and the calculation tabulating i
support discrepancies.
The licensee letter specifically committed to removing the existing support rods on the unstable valve operators and replacing them with more stable supports by the end of 1981.
The attachments indicated support number AFW-15 was unstable.
This is the support for YCV-1045B, which the team questioned during their walkdown.
The NRC letter fowarding the safety evaluation for Generic Letter 81-14 concluded that the seismic qualification of the auxiliary feedwater system was acceptable provided that the four corrective actions committed to by the licensee were taken.
One of these actions (Item B) was to replace existing support rods for valve i
operators with more stable supports. Apparently because the committed completion date was before issuance of the NRC letter, a telephone call was made to the licensee to verify completion of these actions.
The letter documented the NRC's understanding that these actions have been completed.
Notwithstanding these commitments and attempts at verification, the team l
noted the following:
A-42
(1) The valve operator for valve YCV-1045B is currently restrained by a rod which is affixed to a stairpost; the strut substitution committed to by Omaha Public Power District was not implemented; (2) The Omaha Public Power District as-built drawing does not show either the valve operator or the existing rod restraint (Reference 4);
(3) The vendor drawing for valve YCV-1045B could not be obtained to verify the valve and operator weights, and operator offset dimension with respect to the valve centerline; (4) The valve operator restraint was not modeled in the stress analyses; (5) There are no calculations which combine deadload, thermal and seismic stresses in the vicinity of the valve to confirm the structural adequacy of the adjacent pipe; (6) There are no calculations which combine deadload, thermal and seismic loads for the adjacent supports; based on cursory examination of the computer output by the team, the supports appear to be overloaded, and:
(7) The TPIPE and NUPIPE computer runs are not referenced and are therefore not adequately controlled.
BASIS:
The primary basis for this deficiency is USAR Appendix F, which requires that Class I piping systems and equipment be seismically qualified to the Class I standards detailed therein.
In addition, the licensee's commitments in response to Generic Letter 81-14 were not implemented.
REFERENCES 1.
OPPD (W.C. Jones) letter to the NRC (D.G. Eisenhut) response to Generic Letter No. 81-14, dated July 14, 1981.
2.
NRC (R.A. Clark) letter to OPPD (W.C. Jones), fowardinc a Safety Evaluation Report in regard to Generic Letter 81-14 to OPPD dated February 10, 1982.
3.
NRC Generic Letter 81-14, Seismic Qualifications of Auxiliary Feedwater Systems, dated February 10, 1981.
l 4.
OPPD Drawing, " Fort Calhoun Station /CQE Piping Isometrics /5eismic Sub.
System #MS-4099A," Drawing No. D-4318, Sh. 1, Rev. 1, dated August 26, l
1985.
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04.1-1 (Observation) High Power Rate of Change Trip Bypass DESCRIPTION:
A high rate of change of power trip is operable within the reactor protective system between 10 x 10 4 percent power and 15 percent power.
In the original design for Fort Calhoun, a bypass annunciator was automatically illuminated except during plant startup or shutdown between these two limits.
This type of annunciation complies with IEEE Std. 279-1968 (Ref. 1) in that,
"...if the protective action of some part of the system has been bypassed or deliberately rendered inoperative for any purpose, this fact shall be continuously indicated in the control room."
This continuously illuminated annunciator is in conflict with a more recent recommendation for a " dark board" during normal plant operation (Ref. 2).
Consequently, a design change modification (Ref. 3) was proposed to convert the annunciator to indicate the state of a, "...high rate of change of power trip enabled." With this change, the annunciator is illuminated only when the trip function is effective, and is " dark" during those periods when the trip function has been automatically bypassed.
The final design package did not identify the IEEE Std. 279-1968 design basis requirement for this automatic bypass annunciation. As a result, no justification was provided to address the conflicting requirements placed on this particular annunciator. The safety analysis, prepared in accordance with 10 CFR50.59, stated that no alarm signal was eliminated; however, the automatic indication of a protective system bypass has been eliminated by this change.
(Absence of the " trip enable" does not necessarily indicate bypass of the trip function because of annunciator logic changes incorporated with the modification request).
The team believes that if the licensee had thoroughly examined this change the potentially conflicting design objectives could have been satisfactorily addressed and resolved.
The team understands that OPPD is giving further consideration to implementation of this design modification.
i REFERENCES 1.
IEEE Std. 279-1968, Criteria for Protection Systems in Nuclear Power l
Generating Stations, section 4.13.
2.
NUREG/CR-3217, Near-Term Improvements for Nuclear Power Plant Control Room Annunciator Systems, April, 1983.
3.
FC-84-46, High Power Rate of Change Trip Alarm, Rev. O, 3/6/84.
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A 44 i
04.2-1 (Observation) Delta T Power Loop Analysis DESCRIPTION:
A set of replacement resistance temperature detectors has been purchased from Conax along with associated transmitters from Foxboro to replace existing Rosemount detectors and transmitters in the reactor coolant hot and cold leg loops. Technical Sertices was requested to evaluate the impact of this new instrumentation on the reactor protective system inputs to the thermal margin / low pressure calculator drawer.
The Technical Services evaluation was provided in an OSAR-85-83 report dated September 26, 1985. The team determined that:
(1) The analysis involved safety-related RPS channel inputs, but was not specifically identified as being either safety-related or a calculation involving critical quality equipment; (2) The analysis presented input values and final results, but did not provide the calculation formula nor the entry of input values into the formula needed for traceability; In addition, the team noted that applicable Technical Services procedure (Ref.
- 3) does not contain the Critical Quality Element identification requirement of a similar Generating Station Engineering procedure (Ref. 5).
The team believes that the licensee's various responsible design organizations should implement design changes in a consistent fashion, and that in this particular instance the Technical Services procedure lacks desireable controls contained in the Generating Station Engineering procedure.
REFERENCES 1.
FC-84-140, Delta T Power Process Loops.
2.
OSAR-85-83, Uncertainty Evaluation for MR-FC-84-140, 9/30/85.
3.
Technical Services Procedure, N-TSAP-5, Operations Support Report Documentation, Rev. 1, 5/85.
4.
Technical Services Procedure, N-TSAP-8, Analysis Verification, Rev. 1, 5/85.
5.
Generating Station Engineering Procedure, B-9, Technical Calculation Production, Checking, and Approval, 1/84.
A-45
04.3-1 (Deficiency) Limit Switch Circuit Protection by Fusing, MR-FC-84-74A DESCRIPTION:
Subject to postulated submergence, nine safety-related valves had their soler.oids relocated to higher elevations during the previous refueling outage. The velve position limit switches were also discovered to have not been qualifiec for submergence during third party review. However, they were not relocated at the time to avoid additional mechanical complexity. Omaha Public Power District decided to provide low-current fast-acting fuses in the indicator light portion of the valve control circuits to retain operability of the solenoid, even though position indication may be lost or may become ambiguous to the operator.
For the selected design (Ref. 1), a technical assumption that the indicator light fuse (shown as 0.25 amperes in the final design modification package and as 0.50 amperes in the construction design modification package) would interrupt a fault current before the solenoid fuse (10 or 15 amperes) was not justified, particularly since the expected range of circuit current interruption is outside the range of values specified in the manufacturer's catalog. The design engineer did not provide fuse coordination data in either of the design packages; however, the first design package checker's checklist (Ref. 2) had a notation to " verify fuse curves" and the subsequently revised design package checker's checklist required that a calculation of fuse coordination be provided in the design package.
The design package did not provide any indication that the coordination had been confirmed or that it was appropriate.
The team's review of this catalog data (Ref. 3 and 4) indicated that the circuit interruption time differential between the two fuses may be only 10 milliseconds. Unintended circuit interruption by the larger valued fuse would prevent electrical operation of the solenoids for these nine valves, and would impair the control room operator's capability to remotely close HCV-238 and HCV-239 valves for long term core cooling.
On September 17, Omaha Public Power District requested BUSSMANN to confirm the fuse coordination of the selected fuses, and a favorable response (Ref. 5) has been received. A demonstration test is planned by BUSSMANN to confirm their analysis assessment.
BASIS: An identified technical assumption had not been verified during the preparation, review, and approval of the final design modification package in violation of a design evaluation requirement on page B-2.6 of Omaha Public Power District Procedure B-2 and Omaha Public Power District's commitment to section 4.2 of ANSI N45.2.11-1974.
REFERENCES 1.
MR-FC-84-74A, Fuse Protection for Certain Limit Switch Circuits.
2.
Design Package Checker's Checklist, FC-84-74A, Rev. O, 5/31/85.
3.
BUSSMANN " MIN" fuse catalog,10 and 15 ampere ratings.
4.
BUSSMANN "KTK" fuse catalog, 0.25 and 0.50 ampere ratings.
5.
BUSSMANN letter, Fuse Coordination, 9/30/85.
A-46
U4.3-2 (Unresolved Item) ESF Bypass Switch Keylock Provision, MR-FC-81-102 DESCRIPTION:
To simplify the means for bypassing specific engineered safety feature chainels, keylock bypass switches are being implemented into the trip channels for pressurizer low pressure and steam generator low pressure (Ref.
1). Electro Switch Series 20 switches and Hoffman NEMA enclosures with cylinder loc'ks have been selected for this purpose.
The purchase order (Ref. 2) for metal enclosures to house these bypass switches requested that cylinder locks and keys be provided, but did not specify the lock combinations needed to assure that only one channel would be bypassed at any given time. An Omaha Public Power District Form B (Ref. 3) had requested that different keys be used for the individual trip and bypass functions. Relevant design guidance was provided in the reactor protective system description (Ref. 4) for keylock bypasses in that, "...each trip bypass has a different lock cylinder combination; however, corresponding trips in each of the four protective channels have the same cylinder combination...with one key provided for each trip type." Thus, for the reactor protective system, administrative controls on keylock switches were enhanced by an engineering thought process and hardware differences in the keylocks.
The final design modification package contained no requirement for keylock cylinder combinations and the number of keys needed to control bypassing of individual trip channels.
BASIS: The above configuration appears to violate Omaha Public Power District procedure B-2 pages B-2.5 and B-2.6 in that the technical description and design evaluation did not contain all of the equipment requirements necessary to establish an unambiguous design configuration.
REFERENCES 1.
MR-FC-81-102, Bypass or Trip of ESF Channels Without Jumpers, Rev. O, 8/14/85.
2.
Purchase Order 98505-CB, 8/5/85.
3.
OPPD Form B, Technical Services Review and Evaluation, 4/25/83.
4.
ft. Calhoun RPS System Description, Rev. 4, 5/24/84.
5.
USAR section 7.3.1.
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A-47 t
04.3-3 (Observation) Procurement Requirements on Equipment Vendors DESCRIPTION:
Engineering groups within nuclear steam supply and architect engineer organizations that specify and procure safety-related equipment typically require that: (1) plant specific technical requirements for equip:
-t performance be specified to the vendor, and (2) expected equipment performance be confirmed and documented by the design engineer in a traceable manner.
For a number of design modifications reviewed by the team, Omaha Public Power District design engineers have chosen te specify procurement of a vendar product by catalog number in conjunction with submittal of vendor qualificat 6n test reports where applicable. This approach tends to place a greater degree of conformance responsibility on the Omaha Public Power District design engineer rather than on the equipment vendor.
In addition, a complete identification of relevant performance requirements may not be accomplished.
The team has noted two problems in the procurement approach selected by Omaha Public Power District for the modification packages reviewed; namely, (1) important equipment performance requirements have not always been identified, and (2) a confirmation that the vendor's product satisfies the Fort Calhoun need has not been documented in a traceable manner for design verification purposes. For example, (1) When isolators are used between Class 1E and non-Class 1E circuits, one requirement is that the isolator perform its required function during the application of the maximum credible voltage to its output terminals (typically 120 volts AC and 125 volts DC). This requirement was not identified to TEC for Critical Quality Element isolators between safety-related signals and the emergency response facility computer system. The TEC test plan did not include a test of the isolator for application of these voltages to the output terminals. In addition, test reports were not required to be submitted for Omaha Public Power District review.
(2) When keylock switches are used to bypass protective system or ESF trip functions, design control over the cylinder lock combination and number of keys is needed to augment plant administrative controls (see Unresolved Item 4.3-2).
These aspects were not included in the purchase order for MR-81-102.
(3) A new vendor was selected to provide replacement pressure switches for the containment high pressure measurement.
An identification of a requirement for pressure boundary integrity would appear prudent since these switches serve as an extension of the containment boundary prior to being isolated. (Remote manual isolation is provided).
The team believes tLt ecosideration should be given to improving the effective use of documents that can provide design requirements for the design engineer.
Table B-2-1 in Generating Station Engineering procedure B-2 A-48
provides a framework for assuring that design inputs have been considered in the design process. Other pertinent sources for design requirements include the Fort Calhoun USAR and individual system descriptions.
In addition, an item by item comparison of Fort Calhoun technical require-ments with equipment performance data contained in vendor reports would provide better traceability that the procured equipment meets the plant's requirements.
REFERENCES 1.
FC-83-83, Containment Pressure Switches.
2.
FC-83-109, Transfer of P250 Points to the ERFC.
3.
FC-85-62, Replacement of Component Cooling Flow Element.
4.
FC-81-102, Bypass or Trip of ESF Channels Without Jumpers.
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U4.4-1 (Unresolved Item) Design Basis Physical Separation Within Panels DESCRIPTION:
The team has reviewed both current and previously implemented design modifications that involved the physical separation of safety-related cables outside of control room panels and the separation of safety-related and non-safety-related wiring within these panels. The requirement for separation was qualitatively stated in the " Independence" section of IEEE Std. 279-1968.
l The Fort Calhoun plant has committed to meet IEEE Std. 279-1968.
For recent plant modifications, a definitive quantitative design basis for physical separation of redundant safety-related internal panel wiring harnesses is stated as six inches or a physical barrier by an Omaha Public Power District wire list form. During construction, the plant had a requirement for separation within panels (Ref. 3 and 8) and a separation requirement between safety and non-safety cables (Ref. 9). A commitment for separate and segregated routing of each engineered safeguard control channel has been made (Ref. 10).
lhe Fort Calhoun design basis for physical separation is stated in a qualitative (i.e. functional) manner on design documents and in the USAR.
However, a cuantitative design basis needed to provide measurable acceptance criteria does not appear to be stated in a complete and unambiguous manner leading to certain potential deficiencies. For example:
(1) Separation of original wiring within panels is defined only to the field interface terminal blocks; redundant safety wiring separation for plant modifications has been specified, but separation of safety to nor.-safety internal panel wiring or the installation of barriers has not been imposed. A Final Safety Analysis Report Appendix G commitment made in 1970 stated that physical separation of individual chn nel components and wiring is maintaineo wherever practicable-(2) Achievement of internal wiring separation v.. thin panels was a General Electr'c responsibility (Ref. 3); however, the criteria used to accomplish this separation could not be located during the inspection. Original wiring within the panels appears to be Vulkenc 600 volt insulation over multi-strand conductors. Visual io pection of control room panels by the team indicated that separation appeared to hdve been incorporated in the original design; (3) For recent modifications, internal panel wiring uses single conductor wiring covered with an 85% coverage braid (Ref. 6).
The equivclence of this wiring to meet an acceptable distance or barrier criterion has been assumed; however, it has not bean demonstrated; (4) While redundant Engineered Safety Features components implemented for undervoltage protection (Ref. 2) were mounted within separated barrier compartments, their wiring external to these compartments is in direct contact within control room panel CB-4, and; (5) The proposed addition of trip bypass switches (Ref. 1) has safety-related wiring on three wafers of each switch and non-safety-related wiring to an annunciator on the fourth wafer.
A-50
An analysis to confirm that Class 1E circuits would not be degraded below an acceptable level due to their proximity to non-Class 1E circuits was not provided in the design package.
BASIS:
The routing of redundant safety-related wiring in direct contact from an internal panel compartment barrier configuration violates the wiring harness separation requirement imposed by the Omaha Public Power District wire list form. No analysis has been provided to justify the lack of separation for this wiring.
This is a violation of the USAR commitment for separation of engineered safeguard features controls.
A quantitative criterion for separation of safety-related and non-safety-related internal panel wiring could not be located. For the ESF bypass switch modification, no separation criteria for safety to non-safety internal panel wiring have been applied, and no analysis has been performed in lieu of quantitative separation criteria to assure that Class 1E circuits have not been degraded below an acceptable level. Since the non-safety wiring provides a potential common link among redundant channels, this is a violation of the USAR commitment for segregation of engineered safeguard features controls.
REFERENCES 1.
MR-FC-81-102, Bypass or Trip of ESF Channels Without Jumpers, Rev. O, 8/14/85.
2.
MR-FC-77-40, Undervoltage Protection, Rev. O, 8/13/78.
3.
GHDH Letter NY-762-313 to GE, " Contract 762 Panel Wiring," 8/31/70.
4.
IEEE Std 384-1981, Criteria for Independence of Class IE Equipment and Circuits.
5.
IEEE Std 420-1982, Design and Qualification of Class 1E Control Boards, Panels, and Racks Used in Nuclear Power Generating Stations, 6.
Purchase Specification GSEE-0505, Alpha Wire Corporation, Rev. O, 4/28/77.
7.
OPPD Procedure, GSEE-0516, Requirements for Installation of Electric Cables at Fort Calhoun Station, Rev. 2, 7/19/85.
8.
OPPD Contract to General Electric, page H 1-7.
9.
USAR page 8.5-3, item (i) and USAR figure 8.5-1 note 22.
10.
USAR page 7.3-1, section 7.3.1.b.
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A-51
i D4.5-1 (beficiency) Drawing Changes by Procedure A-9, MR-FC-82-178 DESCRIPTION:
Generating Station Engineering Procedure A-9 (Reference 2) specifies that when an existing drawing needs revision during preparation of a modification request, the design engineer is to request a sepia of the drawing.
This requirement provides control of the drawing during consideration of the design modification, assists in documentation of the as-built status, and alerts other users to coordinate any desired changes with other drawing (facility) changes under consideration.
4 Drawings 11405-M-1 and 11405-M-2 (References 3 and 4) were modified to incorporate air filter differential pressure switches without use of the sepia control process specified by procedure A-9.
The drawings were directly modified based on engineering sketches provided with the final design modification request package.
BASIS:
Compliance with the provisions of engineering procedure A-9 was not provided during the development and implementation of a final design modification package.
REFERENCES 1.
MR-FC-82-178, HEPA Filter DP Indication, Rev. O, 1/23/84.
2.
GSE Procedure A-9, Document Control, section 2.3.3.4, 8/83.
3.
P&ID Drawing 11405-M-1, Containment Heating, Ventilation, and Cooling, Rev. 48, 8/13/85.
4.
P&ID Drawing 11405-M-2, Auxiliary Building Heating and Ventilation, Rev. 37, 11/84.
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A-52 I
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04.5-2 (Observation) Flow Element Design Basis Conditions DESCRIPTION: A replacement flow element was specified for the component cooling water system flow measurement.
In this specification, maximum temperature, minimum and maximum humidity, integrated radiation dose, and seismic acceleration values were identified.
The specified values for the mechanical flow element were not consistent with design basis conditions specified for associated electrical equipment in the GSEE-0802 general requirements specification for controlled access areas of the auxiliary building, as shown in the following tabulation:
Parameter FE-498 Specification GSEE-0802 Specification Temperature 120 degrees F 40 to 122 degrees F Humidity 40 to 100%
15 to 100%
6 7
Integ. Radiation 3x10 rads 2x10 rads Horiz. Seismic 3g
.27g (USAR)
Vert. Seismic 3g
.13g (USAR)
During the inspection, it was determined that the temperature value was obtained from an original Gibbs, Hill, Durham and Richardson instrument specification sheet, the humidity range from other unidentified Fort Calhoun documents, the radiation dose from either the equipment qualification program status report for com;,onents in the vicinity of this flow element or from an obsolete inside containment radiation value, and the seismic acceleration values from an engineering judgement assessment.
On a technical basis, the teamconcernregardingtheradgationdosevaluewassatisfiedastheexpected dose is predicted to be 4 x 10 rads.
Although the actual values specified for the flow element are technically acceptable, the team questioned the control process which generated the specifications.
A consistent design basis for operating condition values, except where additional margin is deemed necessary on a case-by-case basis, should be used for equipment procurement. Differences from this plant basis should be identified and justified in the final design package in accordance with the design input provisions of ANSI N45.2.11-1974.
REFERENCES 1.
FC-85-62, Replacement of Component Cooling Flow Element.
2.
GSEE-0802, General Requirements for CQE (Class 1E) Electrical Equipment Required for Use in Controlled Access Areas of the Auxiliary Building Outside Reactor Containment, Rev. O, 7/14/80.
3.
System Component Evaluation Work Sheet, item PCS-412, sheet 4-62, Rev. O, 4/8/85.
4.
GHOR Orifice Plates and Flanges Specification Sheet, item FE-498, sheet 1.14B, Rev. 1, 2/18/75.
A-53
04.5-3 (Unresolved Item) Battery Room Fire Hazard Analysis DESCRIPTION: Approximately five years ago, an extensive fire hazard analysis was performed at the Fort Calhoun Station. For each of the two battery rooms, the significant combustibles were identified as the plastic battery cases, polystyrene separators between the battery cases, and a small amount of electrical cable insulation (Ref. 3).
Durir.g a plant walkdown the team identified a fuse block enclosure constructed of masonite with a fiber board cover in each of these rooms (Battery room arrangement drawings (Ref. 1 and 2)).
BASIS:
The existence of a wooden fuse block enclosure was not identified in the fire hazard analysis of the battery rooms (fire areas 37 and 38). The team could not locate a description of the test for significance determination for combustible materials used by Omaha Public Power District in the fire hazard analysis.
It is indeterminate whether this material is a significant combustible with respect to the published fire hazards analysis.
REFERENCES:
1.
Arrangement Drawing 11405-E-73, Switchgear, Diesel-Generator, and Electrical Penetrations, Elevation 1011 feet, Rev. 26, 3/22/83.
2.
Arrangement Drawing D-4168, section X-X, Rev. O, 1/22/84.
3.
Fort Calhoun Safety Evaluation Report, page 5-23.
A-54
D5.1-1 (Deficiency) Battery Sizing Calculation DESCRIPTION:
The battery must be sized to provide sufficient capacity to supply the direct current loads under all operating conditions without its voltage dropping below a specified minimum value.
Battery voltage under discharge conditions is determined by the state of charge remaining in the cells, the number of cells which make up the battery, and the rate of discharge.
Battery voltage under charge conditions is based upon the number of cells and the battery charger setting in volts per cell.
In order to reduce the maximum voltage of the battery under charge conditions, Omaha Public Power District removed 2 cells from the 60 cell battery (Reference 1).
Removing cells from the battery reduces the battery's capability to supply the required load current without the battery voltage falling below the minimum acceptable voltage. The battery size must be checked under this lower capacity condition.
The battery size was checked by Omaha Public Power District using the calculation method recommended by IEEE 485 (Reference 2).
The battery cell data was correctly used at the lower permissible discharge rate to limit the cell discharge voltage to 1.81 volts per cell (or 105 volts for 58 cells).
However, the team noted that the battery current discharge profile was the same profile used in the 1979 sizing calculation (Reference 3) that was originally used to purchase replacement batteries.
This profile had not been updated even though increased de loading was responsible for planned replacement of the 200 ampere battery chargers with 400 ampere units.
In an t
attempt to determine the adequacy of the 1979 profile, the team found:
l The load table used to construct the discharge profile was I
composed of general loads without supporting references to substantiate detailed loads.
No justification was documented for failing to include major i
loads such as switchgear control power or diesel generator field flashing.
The 1979 calculation did not contain any documented check or verification of the required discharge profile.
BASIS:
Generating Station Engineering procedure B-9 (Reference 4) requires the checker to confirm that assumptions have been justified.
Generating Station Engineering procedure B-11 (Reference 5) also require: the third party reviewer to confirm that the calculation assumptions have been justified.
The inputs and assumptions used in the latest battery sizing calculation were not verified.
REFERENCES 1.
OPPD Modification MR-FC-84-119, Battery Charger and Inverter Replacement.
2.
IEEE Std. 485, Sizing Large Lead Storage Batteries for Generating Stations and Substations, Recommended Practice For.
3.
OPPD Modification MR-FC-79-03, Replacement of Station Batteries.
4.
OPPD Procedure GSE-B-9, Technical Calculation Production, Rev. 8/85.
5.
OPPD Procedure GSE-B-11, Design Verification, Rev. 8/85.
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US.1-2 (Unresolved Item) Battery Charger /DC BUS Coordination DESCRIPTION:
Battery chargers are provided to maintain the battery in a fully charged condition and to recharge the battery following a discharge.
The battery chargers are also the source of the steady state DC power required for normal plant operation.
Because of load growth, the original battery chargers were operating in their overload region. Omaha Public Power District decided to replace the existing 200 ampere Exide battery chargers with 400 ampere battery chargers from Power Conversion Products (Reference 1).
The original battery charger would provide a current limit at 110% (220 Amperes).
As part of the modification to replace the battery chargers, Omaha Public Power District also planned to replace the existing 225 ampere breakers at the DC switchboard with 400 ampere breakers (Reference 2).
Omaha Public Power District stated that the 400 ampere breaker was the largest breaker size that would fit in the existing switchboard.
Omaha Public Power District failed to demonstrate that the new breaker was compatible with the new battery charger.
Omaha Public Power District made the assumption that the battery chargers would limit the charging current to less than 400 amperes based upon the nominal charger voltage and required steady state load.
The team noted that the instruction manual provided with the battery charger stated that the battery charger would go into current limit in the range of 110 to 125% of rated full load.
This would mean that in attempting to recharge a discharged battery, the battery charger would attempt to provide up to 500 amperes.
This amount of current would trip the 400 ampere breaker located at the DC switchboard.
Omaha Public Power District could not produce any evidence at the time of the inspection to demonstrate that the current limit feature of the battery charger could be adjusted to limit the current to below the 400 ampere breaker trip point.
BASIS:
Omaha Public Power District procedure GSE-B-2 (Reference 3) was prepared consistent with commitments to ANSI N45.2.11 (Reference 4) requirements for design change control.
Procedure section 2.5.2 requires that when specific setpoints or limitations are imposed by other systems or components, such setpoints or limitations are to be clearly stated.
Neither the checker or the third party reviewer questioned the compatibility of the new battery charger with the existing switchboard, including the new larger circuit breaker.
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REFERENCES 1.
OPPD Modification MR-FC-84-119, Battery Charger and Inverter Replacement.
2.
OPPD Dwg. D-4341, Issue A, Inverter Replacement and Battery Charger One Line Diagram.
3.
OPPD Procedure GSE-B-2, Production of Design Description and Evaluation Nuclear Modifications.
4.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear l
Power Plants.
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05.1-3 (Observation) Power Cable Sizing DESCRIPTION:
Power cables are sized to consider allowable ampacity, voltage drop and short circuit conditions.
The allowable ampacity for a power cable is dependent upon:
- 1) Type of insulation on the conductor.
- 2) Ambient temperature seen by the raceway.
- 3) Proximity to other cables in the raceway.
Three types of raceways are in general use in power plants.
These are underground ducts, conduits, and cable trays.
The Insulated Cable Engineers Association (ICEA) has established allowable ampacities for power cable addressing the above considerations in their standards (References 1 and 2).
The Fort Calhoun Updated Safety Analysis Report Section 8.5.4 refers only to the IPCEA (currently ICEA) Publication No. P-46-426 cable ampacity limits.
However, the vast majority of power cables are routed in cable tray. The cable selection analysis used in the original plant design is not available to Omaha Public Power District engineers, so it is left to the individual engineer to interpret how this standard applies to cables in cable tray each time a new cable is routed or an existing cable rerouted.
Also the USAR makes specific reference to Article 430-22 of the National Electrical Code (Reference 3, which pertains to motor loads) but makes no reference for similarly derating any other continuous duty loads.
Design of cable sizing would be enhanced if Omaha Public Power District obtained the specific criteria used to size cable routed in cable tray and documented those criteria for future use in a cable sizing guidance document.
REFERENCES 1.
ICEA Publication No. P-46-426, Power Cable Ampacities.
2.
ICEA Publication No. P-54-440, Ampacities in Open-Top Cable Trays.
3.
NFPA-70, National Electrical Code.
4.
USNRC Regulatory Guide 1.64, Quality Assurance Requirements for the Design of Nuclear Power Plants.
5.
ANSI N45.2.11, Quality Assurance Requirements for the Design of Nuclear Power Plants.
6.
MR-FC-84-119, Battery Charger and Inverter Replacement 7.
MR-FC-85-25, Fire Wrapping of Power Cables.
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T 05.1-4 (Observation) Pre-operational Test Requirements DESCRIPTION:
The direct current system consists of large stationary i
batteries, battery chargers, distribution equipment and the de loads.
The equipment and components connected to the dc system are designed to operate over a specified range of voltage above and below the system nominal voltage.
The system minimum voltage is restricted by the allowable minimum battery cell discharge voltage in accordance with the battery capacity sizing calculations.
The system maximum voltage is determined by the setting of the battery charger required to maintain the battery fully charged.
Because of the industry problems experienced with high dc system voltage affecting connected de components, Omaha Public Power District decided, in modification package MR-FC-84-119 (Reference 1), to reduce the system maximum voltage to 135 volts by removing two of the sixty cells that make up each of the station batteries.
With two less cells in the string, the battery charger voltage could be reduced and still maintain the desired volts per cell charging voltage.
Also, as part of this same modification package, the battery chargers themselves would be replaced with larger battery chargers from a different equipment manufacturer.
During the course of the inspection, the team determined that the battery chargers were originally manufactured for the Marble Hill Station and purchased from Public Service Company of Indiana complete with all documentation (Reference 2).
Team review of the original test data for this equipment revealed that the High DC Voltage alarm setpoint was factory set at 150 volts.
No revised setup procedures were available at the time of the inspection.
The team also noted that no surveillance procedures were available for the disconnected cells.
A lower setpoint for the High DC Voltage alarm setpoint would provide the desired protection for the de system.
Surveillance procedures are also needed.
for the spare cells.
REFERENCES 1.
OPPD Modification Package MR-FC-81-119, Battery Charger and Inverter Replacement.
2.
OPPD Purchase Order 079927, Model 35-130-400 Power Conversion Products Battery Chargers.
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05.1-5 (Observation) Inverter Sizing Without Analysis DESCRIPTION:
Safety and non-safety-related instrumentation at Fort Calhoun are fed from four 125 Vdc to 120 Vac inverters.
These de powered inverters provide a source of uninterruptible power for the four safety-related and two non-safety-related instrument buses. The original design of this system included provisions that would permit two safety-related instrument buses to be tied together in the event that one of the four inverters was taken out of service for maintenance.
Whenever this tie was made the inverters would run in their overload region, because of increased loading on these buses since the original design. Also, because of the age of the original inverters, Omaha Public Power District decided to replace them with new units.
The new inverters were purchased from existing stock from the Tennessee Valley Authority.
However, Omaha Public Power District was only able to obtain safety-related inverters of a smaller size than the original design (Reference 1, 2). Omaha Public Power District justified using the smaller inverters for the safety buses by making a one time measurement of the running load on each of the instrument power buses during normal plant operation (Reference 3) and by purchasing two additional inverters for the two non-safety-related instrument buses (Reference 4).
No analysis was performed of the connected load or the effect off-normal plant operation would have on the load requirement because Omaha Public Power District felt that the apparent margin over running load would compensate for any off-normal operating transients.
A well controlled design would establish what specific loads are connected to the instrument inverters and determine the individual demand loading under different conditions of plant operation.
REFERENCES 1.
OPPD USAR Fig. 8.1-1, R3 7/85, Simplified One-Line Diagram, Plant Electrical System.
2.
OPPD Drawing D-4341, Issue A, 6/85, Inverter Replacement and Battery Charger One-Line Diagram.
3.
Telephone Call, H. Faulhaber (GSE) to J. Foley (Ft. Calhoun) 8/2/85.
4.
OPPD Purchase Orders No. 07828 and No. 08008, Elgar Inverters.
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05.1-6 (Observation) Design Interface Control DESCRIPTION:
Major plant modifications require interface between different design organizations.
The design control procedures in use at Omaha Public Power District require that interfaces be considered as part of the design modification process (Reference 1).
Two areas of design interface were examined by the team during this review:
(1) Equipment mounting requires review and verification by the structural department to ensure that safety-related equipment is mounted in accordance with the vendor's seismic qualification.
This review must also verify that building floor loading is acceptable.
(2) Equipment heat loss and ventilation requirements must be reviewed by the mechanical department to ensure that any additional heat loads are accounted for.
The design modification packages reviewed contained reference to these concerns but the design process had not proceded far enough for the structural department to perform any review (Reference 2).
No input to the mechanical department had been performed at the time of the review.
The team concluded that a system does exist which generally questions inter-disciplinary interface.
However; the team is concerned that no inter-disciplinary review had yet been performed by either structural or mechanical departments for the electrical modifications that were scheduled for installation during the 1985 outage.
REFERENCES:
1.
OPPD Design Procedure GSE-B2, Production of Design Description and Evaluation of Nuclear Modifications.
2.
OPPD Internal Memorandum GSE-FC-85-850(E15), 9/4/85, Inverter Replacement.
Seismic Supports.
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D5.2-1 (Deficiency) Fire Wrap Protection for Cable Raceways DESCRIPTION:
Cables for redundant systems are separated from their redundant counterparts to meet the fire protection requirements of 10 CFR Part 50 Appendix R (Reference 1). Where the required separation distance cannot be maintained, fire barriers may be used.
During a previous NRC inspection (Reference 2), a lack of sufficient separation was noted for the pressurizer heater power cables.
In response to the previous inspection finding, Omaha Public Power District prepared modification package MR-FC-85-25 to move the feeder cables to three Bus 3 motor control centers (power source for the pressurizer heaters) from cable trays and reroute these cables in conduit.
These conduits were to be protected with a 3M fire wrapping system.
Because fire wrap reduces the heat transfer from the cable through the conduit, Omaha Public Power District requested 3M to provide cable derating factors for the Omaha Public Power District application.
3M responded with derating factors developed using a heat transfer computer program developed by 3M for this type of application (Reference 3).
Based upon these derating factors, and the general cable ampacity design margins described in the Updated Safety Analysis Report (Reference 4), Omaha Public Power District justified the use of existing cable sizes.
Omaha Public Power District did not determine the actual loads on the motor control center feeder cables in this analysis, nor did they attempt to justify the 3M computer generated derating factors.
In an attempt to verify the 3M program, the team independently estimated the derating factor required for the 3M fire wrap by using the heat transfer method developed by Neher and McGrath (Reference 5).
This method was the basis for the Insulated Cable Engineers Association cable ampacity standard (Reference 6) referenced in the USAR.
The team's estimate for required cable derating was higher than that suggested by 3M.
Omaha Public Power District was not able to explain the computer inputs and outputs used and/or developed by 3M.
In response to the team's questions, Omaha Public Power District requested from 3M a verification of their computer program. 3M supplied a report (Reference 7, developed in response to the team's concerns) based upon test data to justify the required derating factors.
The 3M test data indicated a required derating factor almost twice that determined by the 3M computer program and subsequently used by Omaha Public Power District in the design modification analysis.
BASIS:
Generating Station Engineering procedure B-9 (Reference 7) requires that computer calculations be checked.
Generating Station Engineering procedure B-11 (Reference 8) checklist B-11-lG requires that computer calculations be verified. The checker failed to question the need to know the actual load current on the motor control center feeder cables.
Both the checker and the third party reviewer failed to verify the computer program developed by 3M or confirm that it had been verified.
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REFERENCES 1.
10CFR50 Appendix R, Section III, G.
2.
USNRC Inspection Report.50-285/83-12.
3.
3M letter 7/11/85, Computer Ampacity Determinations.
4.
USAR. Section 8.5.4.
5.
Neher & McGrath, AIEE Paper #57-660, October 1957.
6.
IPCEA P-46-426, Power Cable Ampacities.
7.
3M Report, Ampacity Considerations, October 1985.
8.
OPPD Procedure GSE B-9, Technical Calculation Production, Rev. 8/85.
9.
OPPD Procedure GSE-B-11, Design Verification, Rev. 8/85.
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06.1-1 (Deficiency) Safety Evaluations For Non-Safety-Related Systems Described In The USAR DESCRIPTION:
Non-safety-related final design packages were reviewed in conjunction with the USAR to determine if safety evaluations as required by 10 CFR 50.59 were required, and if so, were properly accomplished and documented in the final design packages.
Each of the final design packages in this review were evaluated against the USAR descriptions to determine if changes to USAR text, drawings and figures would be required as a result of these modifications.
If so, as required by 10 CFR 50.59, a safety evaluation of the design change would be required to determine if an unreviewed safety question existed even though these were non-safety-related systems. 10 CFR 50.59 does not differentiate between safety and non-safety-related systems.
Omaha Public Power District procedure Standing Order G-21, Station Modification Control, discusses safety evaluations for both final design packages and construction packages.
This procedure only requires the preparation of a safety analysis in a Final Design Package if safety-related equipment is involved or impacted.
By virtue of G-21 procedure requirements for the Planner, a construction package safety evaluation should always get accomplished, however, the team considers that a construction package safety evaluation is for construction related activities and does not fulfill 10 CFR 50.59 requirements for a safety analysis of the design aspects of design changes unless those design attributes are specifically addressed.
G-21 also indicates that the final safety analysis of the design is to be part of the final design package.
Review of non-safety-related final design packages revealed that five modifications planned for completion during this outage did not have safety evaluations in the final design packages.
Each of the affected systems or equipment were described in the USAR and it appeared that completion of the modifications would require changes to USAR text, drawings or tables to accurately represent the newly changed systems or equipment.
The modification packages and affected areas of the USAR are discussed as follows:
MR 483-175 Feedwater Regulating System Instrumentation Replacement This modification will replace the existing Feedwater Regulatory System (FWRS) with an entirely new system.
The new system will use two separate controllers, one for downcomer level and one for flow error.
It will also have automatic control above 5% power.
At the time of the inspection, USAR section 7.4.3 specified use of a three element controller using steam flow, feed flow and downcomer level.
USAR Figure 7.4-5 depicted a three element controller.
USAR section 7.4.3 specified manual control below 15% power.
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MR 485-008 Boric Acid Addition System This modification will modify the phosphate addition system to add boric acid for control of intergranular stress corrosion cracking and steam generator tube denting.
At the time of this inspection, USAR section 10.2.2 specified that, " Chemicals are added to the feedwater upstream of SG feedwater pumps for oxygen scavenging and ph control." The team noted that this modification will be adding more chemicals for other reasons.
USAR P&ID M-253 showed piping entry points for " phosphate feed see P&ID M-265."
The team noted that this modification will be adding boric acid at these entry points and not phosphate treatment.
In addition, the new concept of use of boric acid as a chemical control agent in the steam generators did not undergo a safety analysis by engineering.
MR 474B-057 Power System Stabilizer This modification will add a stabilizer to the main generator Alterex Exciter to stabilize generator power in case of fluctuations in the Mid-Continent Area Power Pool (MAPP).
At the time of this inspection, USAR section 8.2.1 had a network stability analysis.
The team noted that this modification will enhance Fort Calhoun Station's ability to handle network fluctuations. USAR section 10.2.4 discussed generator field excitation by the Alterex Excitation System.
The team noted that this modification will add a power system stabilizer to the Alterex Exciter.
MR 483-174 Reactor Regulating System Steam Dump and Bypass Alarm This modification will make wiring changes and additions within the main control boards to provide operators with status of system conditions for dissipating excess NSSS stored energy following a turbine trip.
At the time of this inspection, USAR section T.4.4.2 discussed system design with a list of what the system consisted of as well as system inputs and system outputs.
The team noted that this modification will change wiring and add indicators to the control room.
MR 483-90 Replace LP Feedwater Heaters This modification will replace existing CuNi low pressure feedwater heaters and drain cooler tube bundles with stainless steel units.
At the time of this inspection, USAR Figure 10.2-6 depicted flow, temperature and heat transfer data based on the existing CuNi units.
The team noted that this modification will introduce changes to this data.
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BASIS:
10 CFR 50.59, in part, allows changes to facility as described in the Safety Analysis Report (SAR), without prior NRC approval, if the modifications do not introduce an unreviewed safety question.
The Omaha Public Power District procedure for 10 CFR 50.59 reviews for unreviewed safety questions is Standing Order (50) G-46, Evaluation of Procedures, Procedure Changes, Tests, and Experiments for Safety Evaluations and Status as an Unreviewed Safety Question.
The result of such reviews is a written safety evaluation addressing the three question criteria presented by 10 CFR 50.59.
Safety evaluations are required by 10 CFR 50.59 when USAR text, drawings or tables are changed by facility modifications.
Each of the modifications discussed above were described in the USAR in sufficient detail that changes to the USAR would be warranted.
Accordingly, safety evaluations should have been accomplished in the final design packages.
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U6.1-2 (Unresolved Item) Safety Analyses For Emergency Modifications DESCRIPTION:
Omaha Public Power District procedure Standing Order G-21 allowed emergency modifications to be accomplished by plant personnel with telephone approvals and also allowed issue of final design packages after completion of the modifications.
The team reviewed emergency modifications to determine if design safety evaluations had been accomplished prior to operation of the modified systems.
Generating Station Engineering (GSE) procedure B-2 requires that a safety evaluation be accomplished for all critical quality element (CQE) equipment, and, as discussed in deficiency 06.1-1, 10 CFR 50.59 requires a safety evaluation for design changes to facilities as described in the USAR.
Review of emergency modifications revealed that the following CQE emergency modifications had been accomplished and the affected systems relied upon for operation without a final design safety evaluation.
MR 484-84 DC Grounds on Critical Quality Element (Safety Injection)
Valves MR 483-129 Diesel Generator Speed Sensing Power Supply MR 483-152 Diesel Generator Speed Sensing Power Supply These modifications were completed in May 1984, September 1983, and October 1983, respectively.
Presence of construction package safety evaluations was not looked for in each of these cases since, as discussed in deficiency D6.1-1, construction package safety evaluations do not necessarily satisfy design aspect requirements for final design package safety evaluations.
The design process followed for emergency modifications was a simplified process performed by the plant engineers and not the responsible design organization.
The team considers that a period of time between system modification and completion of the design safety evaluation was acceptable provided a safety evaluation by the responsible design organization was completed prior to relying on the system for plant operation.
BASIS:
These modifications all involved critical quality element equipment.
In accordance with Generating Station Engincoring procedure B-2, a safety evaluation of the design is required for all critical quality element structures, systems or components.
10 CFR 50.59 requires that safety evaluations be performed for proposed changes to the facility as described in the FSAR.
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06.1-3 (Observation) Vital AC Inverter Bypass Mode DESCRIPTION:
The licensee was experiencing several problems with the vital AC inverters.
MR-84-119 (Reference 1) was initiated to correct these problems.
In the original design, the four instrument AC buses (A), (B), (C), and (D) were powered from static inverters which in turn were powered from redundant Class 1E batteries.
Non-safety-related vital AC buses AI-42A and AI-42B were supplied through isolation transformers from vital ac buses C and D, respectively.
There were no provisions for powering these vital ac buses from the station's Class 1E 120 volt ac (interruptible) distribution, nor were any automatic transfer devices incorporated in the design.
The proposed design for the station uninterruptible vital ac incorporated automatic transfer of a vital bus to interruptible 120 vac upon loss of power by a static transfer switch and provisions to manually transfer the bus to interruptible ac power by means of an inverter bypass switch.
The proposed design also provided two new non-safety-related inverters dedicated to buses AI-42A and AI-428.
These inverters contain similar bypass and automatic transfer provisions.
The original design also contained circuit breakers and associated cabling which allowed powering two vital buses from the same inverter (A and C together or B and D together) for purposes of maintenance on the inverters, etc.
The new design does not retain such a feature for the non-safety-related vital ac buses.
During review of the Final Design Package for MR-84-119, the team identified several questions regarding the adequacy of the associated 10 CFR 50.59 safety analysis.
Licensee procedures do not specifically require evaluations and documentation of whether or not Technical Specifications are affected by proposed facility changes performed pursuant to 10 CFR 50.59.
The team noted that several technical specifications are involved with the vital ac inverters.
These include specifications 2.7.1(1) for the four ac instruments buses, specifications 2.7.1(j) for the non-safety vital ac buses, and specification 2.0.1(2) for emergency and normal power sources.
The team noted that the licensee's proposed design has created new possibilities for powering the subject buses from other than their normal uninterruptible power supplies.
The licensee did not incorporate hardware features which would preclude powering more than one of these buses from interruptible power.
In evaluating whether or not the possibility of an accident or malfunction of a different type than evaluated previously in the USAR was created, the licensee determined that:
"No new failure models are created if no more than one inverter is cperated in BYPASS at anytime.
Operation of more than one inverter in the BYPASS mode could create a failure mode which has not been previously evaluated.
Technical Specification 2.7 permits plant operation with one inverter inoperable.
This is justified because all engineered safety feature and reactor protection system channels revert A-67
to or can be placed in a two-out-of-three logic.
However, if two inverters were simultaneously operated in BYPASS, a loss of offsite power combined with failure of a single DC bus could result in complete loss of instrument AC until a diesel had started.
This failure mode has not been analyzed in the USAR.
Therefore, in order to maintain consist ency with the existing USAR and Technical Specifications, the BYPASS. node must be defined as inverter failure."
The team noted that the technical specifications do not specifically refer to inverters, therefore a question is raised regarding the meaning of
" inverter failure." The team also considered that internal interpretations of technical specifications in a safety analysis are not an appropriate method of implementing changes in that such conditions should be clearly and unambiguously addressed in the Technical Specifications.
During this inspection the team identified one other deficiency (D2.2-6) where an internal safety evaluation statement, requiring the operator to secure one of the c.ontainment coolers if all four start following an accident, had not been incorporated into plant procedures.
The team noted that although the interpretation that a bypassed inverter is considered inoperable would reduce the probability that more than one inverter could be powered from interruptible sources, it does not eliminate the possibility.
Operator error, potential common mode failure, etc., could result in more than one vital ac bus powered from interruptible ac sources.
In addition, only interruptible backup power is now available to the non-safety-related vital buses.
This aspect was not addressed in the safety analysis.
The licensee did not consider the basis for technical specification 2.0.1(2) in this analysis.
This technical specification broadly allows consideration that individual systems, components, and devices are operable if either the normal or emergency power source is operable, and allows the governing electric power technical specification limiting condition for operation to control continued plant operation.
The team asked Generating Station Engineering personnel whether or not they consulted the NRC Safety Evaluation Report, documenting NRC review and acceptance of the FSAR, during the preparation of the safety analysis.
The team was informed that although certain Generating Station Engineering personnel read specific safety evaluations when issued by the NRC (for example, with Technical Specification changes), copies of the safety evaluations were not maintained by engineering nor consulted during licensee safety evaluation preparation.
The team obtained a copy of the original Safety Evaluation Report, dated August 9, 1972, and noted that several aspects of the proposed inverter modification could at least be questioned in light of the evaluation.
For example, the report stated that the licensee had originally proposed automatic transfer devices for both the ac and de systens, however, these features were eliminated following NRC concerns regarding jeopardizing redundant power sources.
The team noted that the vital ac buses which are normally de powered through an inverter will now have an automatic transfer to ac power.
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A technical specification change to clearly address the availability requirements for the new inverters, and review of a comprehensive set of NRC safety evaluations by engineers performing safety analyses would minimize the potential for introduction of an unreviewed safety question.
REFERENCES 1.
Modification Request FC-84-119, Battery Charger and Inverter Replacement Lowering Terminal Voltages and Battery Discharge Breakers, Final Design Review dated August 20, 1985.
2.
Fort Calhoun Standing Order No. G-25, Evaluation of Procedures,
" Procedure Changes, Tests and Experiments for Safety Evaluations and Status as an Unreviewed Safety Question," issued November 24, 1984.
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06.2-1 (Observation) Untimely Closeout Of Emergency Modifications DESCRIPTION:
Omaha Public Power District procedure Standing Order G-21 addresses emergency modifications and allows issuance of the final design package by the Generating Station Engineering design engineer after work has j
been completed on the emergency modification.
These design packages are j
called "after-the-fact" design packages.
i Emergency modifications were evaluated by the team for length of time i
required to issue after-the-fact design packages since completion of the i
modification.
Omaha Public Power District procedures provide no guidance i
j for timely issuance of after-the-fact design packages.
Six emergency modifications were noted to have excessive issue times for 4
f after-the-fact design packages.
These are summarized below:
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Time Required Date Mod.
Design Package To Issue Design
]
MR No.
Installed Issue Date Package (Months) i 484-83 Hydrogen Purge May 1984 April 1985 11 Fan Shielding 480-93 Replacement of March 1981 October 1984 42 SI Solenoid Valves 483-07 Alternate Load Jan. 1983 None Yet 32+
Cell for FH-1 t
483-129 DG-2 Speed Sept. 1983 None Yet 24+
l Sensing Power Supply 483-152 DG-2 Speed October 1983 None Yet 24+
Sensing Power Supply 484-84 DC Grounds on May 1984 None Yet 16+
SI Valves Although ANSI N45.2.11 does not specifically address closure times for work i
packages, it is clear from a system acceptance standpoint that an excessive length of time for the responsible design organization to issue their design l
documents is unsatisfactory.
Because emergency modifications were usually i
done by plant personnel and not by the responsible design organization, timely performance of the independent design activity would help to assure that the installed emergency modification was in fact satisfactory from a design standpoint.
This would allow final acceptance of emergency i
modifications by the System Acceptance Committee much sooner.
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06.2-2 (Deficiency) Modifications to AFW Turbine Steam Supply Valves DESCRIPTION: While performing an operability check on the steam driven auxiliary feedwater pump (FW-10) in September, 1978, it was found that an instrument air supply valve to the YCV-1045 operator had been inadvertently closed with the result being that YCV-1045 was in its failed closed position and FW-10 was inoperable.
Subsequently, EEAR FC-78-43 was processed which recommended that the YCV-1045 valve operator be redesigned to fail open, assuring maximum auxiliary feedwater availability upon loss of air.
The memorandom later additionally recommended the addition of air accumulators to the YCV-1045A/B valve operators, which have always been fail open valves.
This would enable remote manual isolation of a tube-ruptured steam generator upon loss of instrument air as per Criterion 57, App. A, 10 CFR 50, which requires the ability to remote manually isolate a closed system penetrating containment.
The original proposed modification changed the failure mode of the air operated AFW turbine steam admit valve (YCV-1045) to fail open from fail closed.
Generating Station Engineering evaluated the emergency status of the modification in June 1979 and determined that the proposed modification would violate containment isolation requirements.
MR 78-43 was revised to required addition of safety-related accumulators to the steam supply valves (YCV-1045A/B).
On March 21, 1980 work was actually completed on YCV-1045 on an emergency basis making the valve fail open; however, no accumulators were installed on YCV-1045 A and B.
In October 1983, during Generating Station Engineering review of the "after-the-fact" Final Design package for emergency MR 78-43, they discovered that the accumulators had not been installed on YCV-1045A and YCV-1045B.
Generating Station Engineering recommended that the plant make arrangements to install accumulators as soon as possible as the operation of these valves would be required during a steam generator tube rupture (Reference 5).
The station initiated a low priority (priority 4) request for a " minor" modification on December 27, 1983. During November 1983, Generating Station Engineering completed the "after-the-fact" Final Design package for MR 78-43.
This package, dated November 8, 1983, noted that air accumulators were to be installed in the future under a new MR 83-158.
The safety analysis included in the Final Design Package discusses the need to isolate the steam supply following a steam generator tube rupture and for containment isolation provisions, and notes the ability of YCV-1045A and B to accomplish this with accumulators.
The unreviewed safety question evaluation addressed whether the probability of occurrence or the consequences of an accident or malfunction of equipment important to safety previously evaluated in the Safety Analysis Report may be increased.
The evaluation concluded that since this modification changed the failure position of valve YCV-1045 and added air accumulators to valves YCV-1045A and YCV-1045B, this will not affect the results of the main steam line break analysis.
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l However, the team noted (as acknowledged in the Final Design Package for MR 78-43) that the accumulators had not been added and it was improper to conclude that no unreviewed safety question existed based upon work to be performed at some future date.
During review of the station's Engineering Evaluation and Assistance Request in December 1984, Technical Services identified the improper " minor" i
classification of the modification request and recommended upgraded priority from 4 to priority 1.
The Technical Services review also resulted in discussions between Technical Services, Licensing, Generating Station i
Engineering and Plant personnel addressing these concerns.
As a result of these discussions (reference 6) the licensee decided to install the accumulators at the next refueling outage, or the next (earlier) outage of sufficient duration.
The licensee also evaluated operation of the plant during the previous six years in light of the requirements of General Design Criterion 57 (reference 1).
The licensee concluded:
I "From 1979 until the present, the requirement of Criterion 57, App. A, 10 i
CFR 50 has been met under normal plant operation, or in the event of a steam generator tube rupture.
It is only when the postulated tube rupture occurs l
in conjunction with a loss of air that the requirement for remote manual
{
isolation of the affected steam generator cannot be met.
However, during this six year interval, local manual isolation of the two-inch steam line l
has always been possible and this operator action would have been performed in the event of a tube rupture coupled with loss of air as per Emergency Procedure EP-30, Step D.8.d.
The plant has determined that time required for i
this operator manual action is not excessive and will insert an appropriate j
statement regarding this requirement in EP-30, to reinforce operator's awareness of this required action to isolate the potential radionuclide leakage path via FW-10 steam feed."
l The licensee further determined that the operation of the plant with the i
described configuration did not constitute an unreviewed safety question and was not reportable.
The team verified that the emergency procedures had been revised as recommended.
l The team determined that the following design control inadequacies relating to failure to incorporate a portion of an approved modification, excessive length of time to process a completed emergency modification, and basing a 10 CFR 50.59 safety evaluation for a completed facility change on work yet to be performed were a deficient condition.
The team also considers that operation of the facility as described was an unreviewed safety question in that the possibility had been created wherein remote manual isolation of the AFW steam supply might not be possible following a steam generator tube rupture i
if offsite power was lost or the non-safety-related instrument air system was otherwise unavailable.
i The team also noted that the USAR does not accurately reflect the as-built configuration for the containment penetrations which are associated with i
YCV-1045A and B.
USAR Table 5.9-1 shows these penetrations (M-94 and M-95) i as Type IVD, containing a single power operated valve whose normal position A-72
is open, fails closed, and accident position is closed.
The team noted that although this depiction is correct for the main steam isolation valves, the AFJ steam supply taps off on the upstream (containment) side of the main steam isolation valves, and that these valves are normally closed, fail open, and accident position is open.
In addition, the main steam isolation valve bypass valves are not shown.
These USAR errors had apparently not been identified and corrected during licensee reviews of these modifications, notwithstanding the licensee's concerns for compliance with General Design Criterion 57.
BASIS:
10 CFR 50.59 requires evaluations of proposed changes to the facility to be made without prior NRC approval, to ensure an unreviewed safety question does not exist.
A proposed change involves an unreviewed safety question if the consequences of an accident previously analyzed in the FSAR is increased or if a malfunction of a different type than evaluated previously in the Safety Analysis report may be created.
10 CFR 50, Appendix A, Criterion 57 - Closed system isolation valves, requires that, "Each line that penetrates primary reactor containment and is neither part of the reactor coolant pressure boundary nor connected directly to the containment atmosphere shall have at least containment isolation valve which shall be either automatic, or locked closed, or capable of remote manual operation."
REFERENCES 1.
CFR 50.59, 50.73(a)(2)(B)), Part 50 Appendix A, General Design Criterion 57, 2.
USAR Table 5.9-1, Containment Isolation Valves, penetrations M-94, 95.
3.
Modification Request FC-83-158, Air Accumulators for YCV-1045A/B, EEAR dated 11/8/83.
4.
Emergency Modification Request FC-78-43, Analysis of Failure Mode of YCV-1045, Safety Analysis dated April 20, 1979.
5.
Memorandum from M. Eidem to W. Gates, Failure Mode of YCV-1045, dated October 27, 1983.
6.
Memorandum from R. Jaworski to W. Gates, Review of Failure Mode Modifications on YCV-1045A/B Steam Supply Valves to Steam-Driven AFW Pump, FW-10, dated January 15, 1985.
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