IR 05000321/1990016
| ML20217A753 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 11/05/1990 |
| From: | Lawyer L, Linda Watson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20217A748 | List: |
| References | |
| 50-321-90-16, 50-366-90-16, NUDOCS 9011210266 | |
| Download: ML20217A753 (33) | |
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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REGION il f
101 MARIETTA STREET,N.W.
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ATL ANT A, OEOROl A 30323
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Report Nos.:
50-321/90-16 and 50-366/90-16 Licensee:
Georgia Power Company P.O.
Box 1295 Birmingham, AL 35201 Docket Nos.:
50-321 and 50-366 License Nos.: DPR-57 and NPF-5 Facility Name: Hatch 1 and 2 Inspection conducted:
October 1-12, 1990 Wu Inspector:
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Lawyer, Team Leader Date Signed V
Team Members:
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Breslau R. Gibbs L. Mellen Accompanying Personnel:
G. Wilford, SAIC Approved by:
M M A/d]Ir2~
// Sffo W9 son, Chief Datte Signed t
L. J.
Operational Programs Section Division of Reactor Safety SUMMARY Scope:
This was a special announced EOP followup team inspection.
The purpose was to verify that corrective actions for previous findings in the area of EOPs and AOPs were adequate.
Results:
The NRC team found, in general, that the licensee's resolution of comments transmitted to them in NRC Inspection Report 321/88-12, 366/88-12 was. technically accurate, timely, and thorough.
The team concluded that the EOPs were adequate to mitigate the spectrum of accidents addressed in the BWROG EPGs and control of equipment necessary to performance of EOP s;:pplcmcrical procedures
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was excellent (paragraph 2.1).
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i Three problem' areas were identified.
These areas are control =of operator action setpoints, resolution of previously identified labeling inaccuracies and technical content of some procedures.
Inadequacies in control of operator action setpoints'are discussed in paragraph 2.d and Appendix B, labeling problems are-
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discussed in paragraph 2.g and Appendix B and technical
inadequacies-in procedures are discussed in-paragraphs 2.c,=2.d,=
4.b-and Appendix B.
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REPORT DETAILS 1.
Persons Contacted Licensee Employees
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Betsill, Operations Unit Superintendent S.
Britt, Operations Department, Plant Operator
- W. Drinkard, Manager SAER D.
Eason, Operations Department, Plant Operator
- A.
Fraser, SAER Supervisor
- G.
Goode, Manager, Engineering Support F. Gorley, Operations Department, Shift Superintendent
- S.
Grantham, Supervisor, Operations Training
- J. Hammonds, Regulatory Compliance Supervisor
- J. Lewis, Operations Manager
- C.
Moore, Assistant General Manager, Plant Support
- D.
Read, Assistant General Manager, Plant Operations R.
Roberts, Operations Department, Plant Equipment Operator
- J.
Seller, SAER Technical Specialist
- L.
Sumner, General Manager, Nuclear Plant
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Tipps, Nuclear Safety and Compliance Manager
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Vidal, Shift Technical Advisor A. Wolfe, Operations Department, Shift Supervisor other licensee employees contacted included instructors, engineers, mechanics, technicians, operators, and office personnel.
NRC Representatives
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Wert, Senior Resident Inspector
- R.
Musser, Resident Inspector
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- Attended exit interview Procedures reviewed during this inspection are listed in Appendix A.
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References to appendices are noted in parentheses.-.For example, (B IV 1) refers to Appendix B, item IV.1.
A listing of abbreviations used.in this report is contained in Appendix I
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2.
Review of IR 321,366/88-12 Concerns a.
Verification and Validation IR 321,366/88-12 noted that the supporting documentation for the EOP development process and formal validation was'under contractor control.
The team observed that the supporting docume.Ttation was now located in the
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onsite document control system.
IR 321,366/88-12 also noted that formal validation for those EOP steps not exercised on the simulator did not include a walkthrough of the procedures in the plant.
The team reviewed the current practice for EOP steps that cannot be validated L
on the simulator.
This method required a wal.;through if simulator validation was not possible.
The tible top reviewr will only be used if the EOP cannot be validated on the simulator or walked through.
Additionally, IR 321,366/88-12 noted that EOP validation and verification on the ARPs and AOPs that implement the PSTG was minimal.
The team found that AOPs, ARPs, and interfacing ops are generally not validated on the simulator, however, the procedures no longer implement PSTG requirements.
Administrative control procedures for EOP validation and verification programs (30AC-OPS-011-OS and 30AC-OPS-006-OS) were reviewed.
Both documents were found to
~ adequately specify a multidisciplinary team approach to V&V.
V&V records for the Revision 4 EOPs were reviewed on a sample basis and showed evidence of a multidisciplinary team approach.
b.
Radiation Release Control IR 321,366/88-12 identified two deficiencies with radiation release control.
These deficiencies had been corrected as follows:
The EPIP was pre"lously identified by licensee documents as a source of jnstructions for radiation release control, but the facility was unable to identify the specific instruction in the EPIP which addressed EPG steps.
The subsequent EOP upgrade to Revision 4 of the BWROG guidelines included instructions within the secondary containment charts for controlling radiation releases.
The EOP upgrade also resolved the failure of previous precedures for radiatjon release to address a radiation release at the alert level pre-scram that may occur as an unmonitored relear.e.
The licensee has deleted the pre-scram.
Now if conditions exist that constitute
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reaching radiation release levels, the flow charts will be entered.
c.
Deviation Documentation and Use of the PSTG as a Technical Basis IR 321,366/88-12 noted a common source for the inspection findings appeared to be that the facility considered the PSTG as a guideline whereas the NRC considered the PSTG as the technical basis upon which to develop the EOPs and upon which their technical adequacy is judged.
The team determined that the licensee now considers the PSTG as the technical basis for the development of the EOPs.
The PSTG had been revised and now implements Revision 4 of the BWROG EPGs with 13 documented plant specific deviations.
The current EOPs were then developed from the PATG with no technical deviations, but with some human tector differences.
There were no differences-in logic or accident mitigation strategy.
IR 321,366/88-12 noted that there was no documentation available to justify the deviations from the PSTG and
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The team observed that the licensee had developed a technical deviation document which addresses the differences between the PSTG and the BWROG EPGs.
IR 321,366/88-12 also noted that there was no documentation available to justify EOP differences from the PSTG.
The team observed that the licensee had developed a document that delineates the differences between the PSTG and the EOPs.
The documentation of the differences was not always detailed enough to determine if adequate engineering analysis had been performed for j
some of the deviations (B II).
Additionally, a comparison between the flow charts and the PSTG documented in IR 321,-366/88-12 revealed
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.several concerns with the details of the Plant Hatch
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EOPs._
The team reviewed a sample of the new flow charts and, with the exception of the comments noted.in Appendix B (B II), the flow charts were found to be adequate.
Technical inadequacies in EOPs identified in Appendix B will be followed up under IFI 321,366/90-16-03.
d.
Operator Action Setpoints 7.R 321,366/88-12 noted that the values for parameters involving action steps in the EOPs were often not the same as those specified in the PSTG.
The team-reviewed
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the deviation document and observed that the setpoints that were different were now described in that document.
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Additionally, IR 321,366/88-12 noted that the limits specified in Path 3 of the EOP flow charts were inconsistent with the PSTG.
The flow charts have been
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completely rewritten and the problem was corrected except as noted in Appenlix B (B II).
Technical inadequacies in EOPs wi.'.1 be followed up under IFI
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321,366/90-16-03.
This inspection, however, noted several additional problems vith the control of operator setpoints, particularly in EOP-14.
The incorrect setpoints indicated ar ineffectivo program for the control of changes to EOP setpoints.
The correct information was located in at least one of the multiple documents that contained the setpoint information.
These discrepancies were not detected during the licensee's EOP review process. Additionally, differences between the EOP setpoints and the-EQ program values were noted.
The details of these differences are described in Appendix B (B II).
The instrumentation for some EOP setpoints were set inappropriately in the field.
An example of this was the alarm setpoints for the E11N600 instruments for the Unit 1 Maximum Normal Values (temperature) for the diagonal' rooms.
The Maximum Safe temperature values for RCIC, HPCI, and the steam tunnel inconsistently referred to the EQ data for maximum room temperature in that some of the Maximum Safe Operating temperatures did not correspond with the EQ room temperature profiles, r
The hi-hi level column on table 5 of EOP-14 referred to the incorrect alarm setpoints.
For example the hi-Pi-hi value was reference 1 instead of the hi-hi value, and the i
setpoint given in tlo ARP did-not correspond to the EOP setpoint, the actua) instrument setpoint, or the instrument setpoint index.
The inappropriate setpoint change methodology and the incorrect EOP setpoilts are identified as IFI 321,366/90-16.
e.
Entry and Exit Conditions The licensee's previous set of EOP' procedures consisted of ARPs, AOPs, Flow Charts, EPMs and EPIPs.
Each of these procedures contained procedural guidance from the EPG.
All were_ required to implement the symptom based EOPs.
The operators would enter an ARP, then go to an AOP, then if necessary direct a scram, at which time the flow charts were entered.
During this lengthy process, conditions such as adverse containment pressures or
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radiation levels could unnecessarily continue without attention from the operator until the operator could progress through the EOP.
The licensee's revised EOPs do not rely on APPs or AOPs to accomplish emergency mitigation.
The EOPs now consist of eight flow paths augmented by twelve supplemental procedures.
Any occurrence developing the PSTG entry conditions, with or without a scram, will immediately cause the operators to enter a specific EOP flow chart to mitigate that emergency.
f.
Procedure Administrative Controls 1)
Administrative Controls for ARPs and AOPs IR 321,366/88-12 noted that the administrative controls for ARPs and AOPs were not the same as EOPs.
It stated they should be since the old'
ARPs/AOPs implemented PSTG requirements.
Discussions with the licensee indicated that there
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are no EPG actions remaining in the ARPs or AOPs.
Therefore, they need not be subject to the same administrative controls.
2)
Ongoing Evaluation of EOPs IR 321,366/88-12 reported that the individual conducting the annual review of EOPs was not required to sign the review sheet, and that there were no specific requirements which provided the bases for the annual review.
The team reviewed the two documents that control this annual review, (30AC-OPS-007-OS and 10AC-MGR-003-OS) and. concluded that these problems had been corrected.
3)
Operator Feedback IR 321,366/88-12 noted that operator feedback was
not actively solicited during EOP training.
Discussions with the licensee revealed that operator feedback was actively utilized during EOP Revision 4 development and is currently being used in operator training.
4)
QA Involvement IR 321,366/88-12 noted that a QA audit of EOP flow charts and end path manuals resulted in similar findings to that of the EOP inspection team.
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The concern was that an in-depth review of root cause was not accomplished.
Also cited was what was considered inadequate followup action regarding how _
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widespread these concerns were.
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The team discussed this finding with QA personnel to determine its current status and to determine the current extent of QA involvement in the EOP program.
These findings and corrective actions included:
a)
The initial EOP inspection occurred during the middle of the corrective action cycle for the QA
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audit dated September 15, 1987.
Corrective action was complete by December 21, 1988.
A followup QA audit-was then satisfactorily accomplished.
b)
QA personnel stated that EOPs have been and will l-be covered as part of the Operations audit. The L
inspection team reviewed the Audit Planning schedule and verified the EOP portion is planned
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to occur at least on an annual basis.
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The next EOP audit is scheduled in 1991 as part l
of the Operations audit.
QA personnel explained
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that the audit would most likely consist of a review of celected EOPs against WG 11.
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d)
As part of the Procedure Controls audit, QA l
conducts an audit to ensure that the Operations Department is conducting annual reviews of EOPs
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Adequacy of EOPs are also covered by other audit types such as simulator certification and training audits.
5)
Quality of Control Room Drawings and Procedures Paragraph 11 of IR 321,366/88-12 identified deficiencies in the quality of various types of f
emergency procedures in the control room.
Review of this area during this inspection determined that the AOPs, ARPs, supplemental EOPs, and EOP flow charts
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were legible, well organized and were neatly filed and tabbed.
g.
Labeling and Nomenclature The executive summary and paragraph 5 of IR 321,366/88-12 identified a concern regarding inconsistency between
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L plant labels and emergency procedure nomenclature.
Review of this area during this inspection by followup L
of previously identified deficiencies and by review of
additional procedures determined that the labeling problem addressed in the previous inspection had not been corrected (B II).
This item will be reinspected in a future inspection under IFI 321,366/90-16-01.
h.
Support Equipment The team noted during walkthrough of the flow charts and supplemental procedures that tools and equipment needed
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to implement the EOP mitigation strategy were dedicated L
for "EOP use only" and were readily available and I
clearly tagged indicating location and use.
Once the operators. progressed through the flow charts to the supplemental procedures, the supplemental procedures contained steps directing the operators to install l
jumpers and/or to disconnect leads from designated
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locations within control panels.
The team noted that once the operator entered the control panels, each ccnnection was clearly identified by a pink " possum vail".
These possum tails were immediately noticeable l>
atd were clearly. marked as to connection points.
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Simuistor Observations The inspection team observed four scenarios performed by the licensee in order to verify the adequacy of several l
of the.EOPs and their supplementary procedures.
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scenarios involved (1) a loss of all feed requiring-steam cooling; (2) loss of high pressure feed /
injection with core spray / lowering suppression pool level; (3) loss of drywell chillers / emergency depressurization; and, (4) total loss of AC for greater
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than 15 minutes.
The inspection team concluded that the L
EOPs and supplementary procedures utilized-in these scenarios were adequate to accomplish accident mitigation.
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Human Factors The primary human factors concern.of IR 321,366/88-12 was the overall complexity of the flow charts.
This complexity resulted in procedures that were difficult to use, understand, and read.
The major contributing factor to this complexity was the high level of detail found in the procedure..
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These initial concerns can be summarized as follows:
1)
Inconsistent transition methods 2)
Inconsistently structured decision steps 3)
Unnecessary memory demands on operators 4)
Improper use and placement of notes and cautions 5)
Poor graphics - inadequate print size, lack of white space, light glare on charts, low color contrast 6)
Complex sentence structure 7)
WG inadequacies 8)
Lack of placekeeping methods 9)
Inadequate table space In general, the inspection team found that the new Revision 4 procedures are significantly improved in all of the above areas, k.
Complexity of EOP Flow Charts Paragraph 8 of IR 321,366/88-12 indicated that the complexity of the EOP flow charts required a substantial amount of training in order to properly train operators in their use.
This paragraph also indicated that the operators considered that the flow charts provided more detail than was required to adequately perform the procedures.
The executive summary of IR 321,366/88-12 contained numerous examples of' human factors concerns.
Simplification of the flow charts under the licensee EOP upgrade project, as described in paragraph 4'.a.,
resolved these concerns.
1.
Containment Venting The IR 321,366/88-12 team noted that the 2 inch flow control valves for the containment vent valves were not environmentally qualified and that there were several differences between the Unit 1 and Unit 2 containment purge lines.
This inspection determined that the purge paths had been revised and were the same for both units.
The emergency containment venting procedure and methodology has been revised to include a drywell destructive vent path which will vent the suppression.
pool or the drywell into the reactor building in the event that pressure cannot be maintained below 49 psig.
This flow path is through duct work that is~ designed to fail and vent to the reactor building.
The SGTS will
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then be aligned to the reactor building to process the l
released gasses.
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IR 721,366/88-12 noted that excessive drywell pressure could close.the excess flow isolation dampers'in the 18 inch SGTS forcing the flow through the two inch bypass line around the damper.
The team reviewed this and determined that this existed to prevent damaging SGTS.
As described above a destructive vent path has been included in the venting procedures to allow the use of SGTS if drywell or suppression pool pressure exceeds 49 psig.
In a letter to NRC dated October 24, 1989, the licensee voluntarily committed to jnstall a hardened vent to reduce the risk associated with the long term loss of decay heat removal.
The licensee will work with.the BWROG to develop specific and generic guidelines for the installation of these vents. The current schedule indicates that the vents will be installed at the end of cycle 14 on Unit 1 and the end of cycle 10 on Lnit 2.
There were no violations or deviations identified in this
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area.
3. Review'of the SER on Procedure Generation Package a.
Plant Specific Technical Guidelines i
The SER stated the PSTG should be revised.to conform with Revision 4 of the BWROG EPGs.
The SER further stated that safety significant deviations should be documented, justified, and archived for future reference.
The team reviewed the completed documentation and determined that'with the exception of the comments detailed in Appendix B (B II), the licensee
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had completed these tasks.
b.
Writer's Guide The inspectors found that the new EOP WG provides sufficient guidance to provide for consistently prepared-and revised, high quality'EOPs. Specific concerns delineated in paragraph 2B of the SER have been either adequately addressed-in WG-11 or are no longer applicable to Revision 4 of the EOPs (C II).
c.
Procedure Generation Package Paragraph 2.B of the SER on the PGP included several additional comments for licensee consideration in revising the PGP.
The details of these comments are addressed in Appendix C (C IV) to this report.
The licensee had taken appropriate action on all of the SER comment,
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Verification and Validation The team found that the licensee had adequately addressed the SER items on V&V.
The details of these actions are in Appendix C (C III).
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Training The team found that all issues raised in the SER had j
been adequately resolved by the licensee in current administrative controls and practices (C III).
The team j
noted that changes had not necessarily been made to the
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PGP since it is not and was not required to be kept
updated.
There were no violations or deviations identified in this area.
4.
Review of Updated Procedures a.
Flow Charts and Emergency Procedure Guidelines The team noted that the legibility of the EOP flow charts had significantly improved since IR 321,366/88-12.
The most significant technical difference was a.
total rewrite of all EOPs to closely follow the EPGs.
The flow charts were well organized and the operators interviewed demonstrated a comprehensive knowledge of the flow paths.
The enlarged print size and increased use of white space has significantly improved readability and useability of the BWROG EPG Revision 4 flow charts.
b.
Other Techt.ical differences exist between the EOP and RCIC operating procedures for actions taken to initiate
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alternate boron injection.
Details are contained in
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Appendix B~(B II).
This item will be reinspected in a future inspection under IFI 321,366/90-16-03.
There were no violations or deviations identified in this area.
5.
Followup of Licensee Long-term Operational Upgrade Efforts The licensee voluntarily initiated a program in April of 1988 to upgrade certain aspects of operational performance.
Long-term operational upgrade efforts in the areas discussed below were reviewed during this inspectio.
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a.
Consolidation or Elimination of Notes, Cautions, and
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Restorations L
Item 4.a of the 1988 EOP improvement project committed i
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cautions, system restorations and system operations from the EOPs. The following has been accomplished in-the L
Revision 4 EOPs:
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1)
Fire notes have-been eliminated from the flow charts and are contained in the fire procedure.
2)
Instructions on operation of systems operator and l
system restorations are now referenced in-the appropriate system operating procedures and I
supplemental procedures.
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Caution' summaries now appear in the flow path with l
detailed caution statements at the bottom of the
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flow chart.
This item is closed.
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Minimize Steps Item 4.b of the 1988 improvement project committed the licensee to minimize the steps in the EOPs.
The team reviewed Revision-4 of the EOPs and determined that the
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licensee had complied with this commitment.
This item
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is closed.
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c.
Language Improvements The licenses committed-to improve the language of EOPs as item 4.c of their 1988 EOP improvement project in order to provide consistent operator response to plant events.
The new EOPs closely follow the EPGs and the majority of the wording is extracted exactly from the l
EPGs.
Improvements have also been made in the licensee's WG for preparing the EOPs.
This item is closed.
d.
Expand Print' Size The inspection team assessed the licensee's corrective actions associated with item 4.d-of the licensee's 1988 EOP. improvement plan.
This was identified as (long.
term) action to expand the print size of the EOP flow paths. -The team noted that adequate print size enlargement, which facilitates the usability of the flow charts, had been accomplished.
This item is close l
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There were no violations or deviations identified in this i
area.
6.
Actions on Previous Inspection Findings (92701)
a.
(Closed) IFI 321,366/88-15-01: Comparison of the EOPs i
and the EPGs and justification of plant specific l
differences.
The EOPs and the EPGs were the same except l
as noted in the appropriate deviation documents, i
b.
(Closed) IFI 321,366/88-36-01: This item addresses
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l-cables entering the main control room. panels from the
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cable spreading room that do not appear to be tied off
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to the cabinet in a way that would prevent loading other previously run cables or loading the state-blocks to which wiring is terminated.
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situations and conducted a walkthrough to assess the j
extent of the noted conditions.
The results were to
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receive an engineering evaluation with subsequent corrective actions initiated.
The inspection team's review noted that the results of
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l the licensee's review determined that the cables that
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appeared to be too tight did not have a potential for j
differential movement and would not be affected during l
or following a seismic event.
The licensee's evaluation i
results are considered to adequately address the concern of this IFI.
However, this same licensee review noted that the cables which were " unsupported or pulled too tight as described in this IFI should be modified to comply with Plant Hatch Procedure (52CM-MEL-003-05]"..No such procedure exists; however, procedure 52GM-MEL-003-OS,.
Cable / Raceway Installation and Cable Terminations does apply.
Tne team noted that documentation does not exist
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that substantiates that the cables.have been evaluated
and corrected as necessary=to meet procedural requirements.
The licensee's corrective actions to address modifying the cables to meet procedural requirements will be inspected during a future inspection and will be inspected under IFI 321,366/90-16-04.
There were no violations or deviations identified in this
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7.
Exit Interview The inspection scope and findings were summarized on October 12, 1990, with those persons indicated in paragraph 1.
The NRC described the areas inspected and discussed in' detail the inspection findings listed below.
No proprietary material is contained in this report.
No dissenting comments were received from the licensee.
Item Number Status Descriution. Paracraoh
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321,366/90-16-01 Open IFI-Resolution of previously identified labeling inaccuracies
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(reference paragraph 2.g).
321,366/90-16-02 Open IFI-Control of operator action setpoints (reference paragraph 2.d).
321,366/90-16-03 Open IFI-Technical content of some procedures (reference
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paragraphs 2.c, 2.d, and 4.b).
321,366/90-16-04 Open IFI-Correction of cable spreading room cables to meet procedural requirements-(reference paragraph 6.b).
"J21,366/88-15-01 Closed IFI-Comparison of EOPs and EPGs (reference. paragraph 6.a).
321,366/88-36-01 Closed IFI-Corrective action for cable spreading room cables (reference paragraph 6.b).
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e Appendix A Procedures Reviewed The following documents were reviewed to assess the licensee's
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upgrade to Revision 4 of the BWROG EPG:
Unit 2 Plant Specific Technical Guidelines, Revision 0 Attachment 1 EPG to PSTG Justification Document Attachment 2 EPG Deviations Attachment 3 PSTG to EOP Comparison Document WG-11 Preparation of Emergency Operating Procedures The following procedures were reviewed in assessing the adequacy of the EOPs:
i 10AC-MGR-003-0S, Rev.12 Preparation and Control of Procedures 30AC-OPS-006-OS, Rev.3 Verification Program For Emergency Operating Procedures l
30AC-OPS-007-OS, Rev.4 Emergency Operating Procedure
Revision Requirements 30AC-OPS-011-OS, Rev.0 Validation Program For Emergency Operating Procedures 30AC-OPS-013-0S, Rev.0 Use Of Emergency Operating Procedures 30AC-OPS-014-0S, Rev.0 Control of Operator Aids 31EO-EOP-010-2S, Rev.0 RC RPV Control (Non-ATWS)
31EO-EOP-011-2S, Rev.0 RCA RPV Control (ATWS)
31EO-EOP-012-2S, Rev.4 PC-1 Primary Containment Control 31EO-EOP-013-2S, Rev.4 PC-2 Primary Containment Control 31EO-EOP-014-2S, Rev.4 Secondary Containment Control, Radioactive Release Control 31EO-EOP-015-2S, Rev.0 CP-1 Alternate Level Control, Primary Containment Flooding, Steam Cooling, & Emergency RPV Depressurization 31EP-EOP-016-2S, Rev.0 CP-2 RPV Flooding 31EO-EOP-017-2S, Rev.0 CP-3 ATWS Level Control 31EO-EOP-100-2S, Rev.0 Miscellaneous Emergency Overrides 31EO-EOP-101-2S, Rev.0 Emergency Containment Venting 31EO-EOP-102-2S, Rev.0 ed 1 RPV Venting During' Primary Containment Flooding 31EO-EOP-103-2S, Rev.0 EOP Control Rod Insertion Methods 31EO-EOP-104-2S, Rev.0 Primary Containment Venting for Hydrogen Control 31EO-EOP-105-2S, Rev.0 Primary Containment Water Level Determination 31EO-EOP-106-2S, Rev.0 Restoration of RPV Water Level Pollowing RPV Flooding 31EO-EOP-107-2S, Rev.0 ed 1 Alternate RPV Pressure Control 31EO-EOP-108-2S, Rev.0 ed 1 Alternate RPV Depressurization 31EO-EOP-109-2S, Rev.1 Alternate Boron Ejection 31EO-EOP-110-2S, Rev.0 Alternate RPV Water Level Control
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Appendix A
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'.31EO-EOP-111-2S, Rev.0 ed 1 Emergency Opening of MSIVs l
31EO-EOP-112-2S, Rev.0 Primary Containment Flooding l
34AB-OPS-002-2S, Rev.3 Small Pipe Break Inside Primary i
Containment and RPV Water Level Corrections L
l 34AB-OPS-010-2S, Rev.5 Loss of Plant Service Water
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34AB-OPS-060-2S, Rev.1 Scram Procedure 34GO-OPS-013-2S, Rev.8 ed 2 Normal Plant Shutdown 34GO-OPS-014-2S, Rev.3 ed 1 Fast Reactor Shutdown 34GO-OPS-087-2S, Rev.2 ed 1 Suppression Chamber Fill and Drain 34IT-EOP-001-2S, Rev.2 EOP Equipment Checks 34SO-C11-005-2S, Rev.5 Control Rod Drive Hydraulic System 34SO-E11-010-2S, Rev.8 ed 1 Residual Heat Removal System
.34SO-E41-001-2S, Rev.7 ed 1 High Pressure Coolant Injection (HPCI) System 34SO-E51-001-2S, Rev.11 ed 1 Reactor Core Isolation Cooling (RCIC) System 34SO-P33-001-2S, Rev.5 ed 1 Primary Containment Atmosphere H202 34SO-P64-001-2S, Rev.8 Primary Containment Chilled Water System 34SO-T41-005-2S, Rev.2 ed 2 Reactor Building Ventilation System 34SO-T41-006-2S, Rev.4 ed 1 Refueling Building Ventilation o
System i
l 34SO-T46-001-2S, Rev.5 Standby Gas Treatment System L
34SO-T47-001-2S, Rev.1 ed-1 Drywell Cooling System l
34SO-T48-002-2S, Rev.5 ed 1 Containment Atmosphere Control and i
Dilution System i
34SO-T49-001-2S, Rev.4 Post'LOCA Hydrogen Recombiner
l System Operating Procedure 34SO-U41-001-2S, Rev.4 ed 1 Turbine Building Ventilation System j
1 l
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APPENDIX B Technical and Human Factors Comments This appendix contains technical and human factors comments and observations.
Unless specifically stated, these comments are not regulatory requirements.
However, the licensee acknowledged that the factual content of each of these comments was correct as stated.
The licensee further agreed to evaluate each comment, to take appropriate action and to document that action.
These items will be reviewed during a future NRC inspection.
I.
EOP Example Closeouts from IR 321,366/88-12 1.
Paragraph 4.b, example 1 a.
This example noted that comparing the mitigation of a low level entry condition on Path 3 of the EOP flow charts (the normal SCRAM procedure) with the low level response of the PSTG contained variances in steps and setpoints.
Most notable of these variances was that flow Path 3 had the operator proceed through forty-three steps before asking if level could be maintained above +12 inches and if not directing the operator to proceed to Path 4.
The inspection team determined from a comparison of the EPG and the revised EOP flow chart, 31EO-EOP-010-2S, coupled with a walkthrough, that the flow chart adequately follows the guidance of the EPG and that previous variances between the EPG and the EOP flow path were corrected.
2.
Paragraph 4.b, example 2 a.
IR 321,366/88-12 noted problems with the entry conditions for RPV pressure control.
The team reviewed the current mitigation strategy.
The entry conditions were appropriate.
3.
Paragraph 4.b, eyample 3 a.
IR 321,366/88-12 noted several discrepancies between the PSTG and the EOP for monitoring and control of reactor power.
These problems were not observed by the team.
4.
Paragraph 4.b, example 4 i
a.
This item reported that the RPV flooding EOP accounted for non-isolation of HPCI and RCIC when they were being used for boron injection but that this action conflicted with the PSTG.
Review of the revised RPV flooding flow chart and the associated
_
.-
$.
,.r
.
..
Appendix B
portion of the revised PSTG determined that they
,
were in agreement concerning isolation of HPCI and RCIC, and both were in accordance with the EPG.
5..
Paragraph 4.b, example 5 a.
This item reported a conflict between the PSTG and
,
the EPM concerning operator actions on high suppression pool level.
Review of the new PSTG and EOP flow chart determined that they were-in agreement and also agreed with the EPG.
,
6.
Paragraph 4.b, example 6 a.
This item reported that. flow chart 1, Caution 21
provided an entry condition for hydrogen contrary to the PSTG.
The new Primary Containment flow chart
and the new PSTG provided this requirement and agreed on the hydrogen value.
7.
Paragraph 4.b, example 7 a.
This item. reported that flow chart 1 and the PSTG conflicted concerning SBLC initiation considering suppression pool temperature.
Review of the new RCA RPV. Control (ATWS) flow chart and the new PSTG determined that they were in agreement concerning SBLC initiation, and agreed with the EPG.
8.
Paragraph 4.b, example 8 a..
This item reported that the PSTG included an entry condition into Secondary Containment Control that was not included in the EPM.
Review of the new PSTG j
and the new Secondary Containment Control flow chart
determined that the entry condition was included in both documents, and that the-entry condition agreed with that specified in the EPG.
9.
Paragraph:4.b, example 9 a.
This item reported a conflict between PSTG Caution 14 and EPM 4.125 concerning operator actions related to RPV depressurization and a check of the availability of low pressure motor driven injection systems.
This check was not included in the new PSTG or the new flow charts due to the fact that Revision 4 of the EPG deleted this requirement.
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i
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Appendix B-3'
10. Paragraph 4.b, example 10 a.
This item noted that in the primary and secondary containment control procedures ~both pre-scram and in the EPM, concurrent control of all containment
_ parameters-(i.e., suppression pool temperature, L
suppression pool level, and containment pressure)
were not procedurally required whenever an entry
.
'
condition existed as provided for in the PSTG.
The licensee _has deleted both.the pre-scram procedures and the EPM.
The revised flow charts for
primary and secondary containment control specify
>
I concurrent control of all containment parameters (i.e. suppression pool temperature, suppression pool level, and containment pressure).
11. Attachment B, paragraph A a.
IR 321,366/88-12 stated that the EOP equipment
,
cabinet was inspected weekly.
The team found the current practice for the inspection of all EOP
'
required equipment to be adequate.
EOP equipment was stored in a variety of locked containers.
The i
tamper. seals were inspected monthly and the contents of the storage containers are inventoried annually.
After a review of previous EOP equipment practices, 4.t was determined that this was the method that was in place at'the time'of IR 321,a66/88-12.
12. Attachment B, paragraph B a.
Sex cal minor comments were identified in IR 321,366/88-12-on the walk:through of the Containment Control Guideline,.Drywell Pressure and Temerature Control procedures._ The team reviewed these comments and determined that they had been adequately resolved.
13. Attachment B, paragraph C
a.
The problems identified in this paragraph concerned operating procedures 34SO-E41-001-2S (HPCI system)
and 34SO-E51-001-2S (RCIC system) which are no longeria part of the EOPs.
Procedure 31EO-EOP-109-2S'took.the place of these procedures.
P,rocedure 31EO-EOP-109-2S was walked through during this L
I inspection.
The results of this walkthrough are included in Appendix B, paragraph II'(B II).
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-Appendix B
14. Attachment B,. paragraph.D, path 1 a.
Para. D (introduction):
The labeling deficiencies discussc0 in this paragraph were still a problem.
Various walkthroughs during this inspection confirmed this conclusion (B II).
,
b.
Para. D.1:
The path 1 flow chart no longer existed.
The paragraph D.1 deficiency concerning the statement "If installed" did not exist on the replacement flow chart (RCA).
c.
. Para. D.2:
This' item identified that pump 2E21-C003 was incorrectly listed on path 1, grid F-5.
Path 1 no longer exists.
The-pump was correctly listed in the replacement EOP (31EO-EOP-110-2S).-
d.
Para. D.3:
Tha improperly numbered steps in note 16 had been corrected on the new EOP.
.
e.
Para. D.4:
The comment concerning note 16, step A.1
,
no longer applies.
The chart was deleted.
f.
Para. D.5:
Frame locations for the referenced jumpers / lifted leads were specified in the new EOP (31EO-EOP-100-2S).
y g.
Para. D.6:
This item, reported that only one-l termination needed to be lifted to allow 2P70-F005
,
~
to fail open rather than two leads'as specified.
The new EOP (31EO-EOP-111-2S). lifts TB1-105 which was satisfactory in accordance with drawing H27233.
h.
Para. D.7:
This item reported that instrument readings specified in-EOPs.did not consider readability of the instrument.
Discussion with licensee personnel indicated that the new EOPs were j
written considering this attribute.
All numerical
'
values in the new EOPs with the exception of j
annunciator and trip setpoints were written considering instrument readability.
1.
Para. D.8:
The installation of the gauges discussed
,
in this paragraph is no longer accomplished by the
'
EOP.
j.
Para. D.9:
This item was incorrect as stated in IR 321,366/88-12.
The specific valves at the grid I
l coordinates referenced in this paragraph were not
,
locally operated valves.
The licensee does provide reference to location for locally operated valves.
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Appendix B
Several examples of this practice were observed during-this inspection, k.
Para. D.10:
The SPDS was very easy to use._ Listing of SPDS frame numbers on the flow charts would only I
clutter the charts.
1.
Para. D.11:
This item reported a conflict between the PSTG and notes on path 1 concerning use of the CRD system.
The new PSTG and EOP were consistent.
m.
Para. D.12:
This item reported that the top of the fuel was not indicated on the level recorder.
The top of fuel was not indicated on the control room -
recorder but was indicated on the control room level indicator.
This item was closed.
.15.
Attachment B, paragraph D, path 3 a.
All items concerning this path were corrected with
,
l the exception of the item numbered Path 3, D.4.
The l
Group 3E isolation valves 2C51-J004A,B,C,and D were l
not labeled on the TIP drawers.
L 16.' Attachment B, paragraph D, path 4
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Lt a.
All items concerning path 4 were corrected.
II. Comments on new procedures reviewed during this inspection
~ 1. -
_
L a.
Step 4.2.3.1:
The step contains a typographical
'
error.
The word "bove" may have been intended to be
"above".
2.
31EO-EOP-011-2S a.
' General comment:
There was no verification r
signature on placard RC-1 to verify'the accuracy of
,
the information of this operator aid.
This
'
condition was also noted on placards RC-2, TC-l'and the SRV sequence placard.
u 3.
31EO-EOP-012-2S a.
BWROG EPG Entry Conditions third bullet:
This entry condition referenced a containment temperature limit j
of'90 Degrees.
This was not applicable at Plant
-
Ilatch.
The deviation document did not state thi,
_ _ _ _ _ _ _ _ - - _ _ _______ - - - - - - _ - - _ _ _ _ _ - _ - _ - _ - - - - _ _ - _ - - - _ _ - _ _ _ _ -
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Appendix B
b.
At A-2:
."he BWROG EPGs stated that the primary i
containment hydrogen concentration should be at 2 percent.
The PSTG states that setpoint should be at 2.5 percent.
The deviation document references
--
drawing 34AR-700-029-2S as justification for the deviation; however, there was no engineering evaluation for this deviation.
c.=
At A-9:
The BWROG EPGs stated that the high drywell i
setpoint should be 2 PSIG.
The PSTG states that
!
setpoint should be 1.85 PSIG.
The deviation
,_l document references drawing A-26497 as justification for the deviation; however, there was no engineering
-
evaluation for this deviation.
d.
At B-4:
This stop required that water level be i
maintained between 346 inches and 150 inches.
With decreasing reactor vessel water level, the core l
!
spray system may be in use for vessel make-up and could be unavailable for suppression pool make-up.
Additionally, the RHR system may be in use or
--
aligned-in the LPCI mode and unavailable for suppression pool level control.
The referenced-mitigation procedures do not address these cases.
--
e.
At.B-7 and.C-7:
These steps did not clearly define
l-the difference between available suppression pool cooling and ALL available suppression pool cooling.
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4.
31EO-EOP-014-2S a.
At C-2:
This step required the operators to operate
,
area-coolers.
Additional guidance is required in-
!
this step to specify which area coolers to operate.
'
or which procedures to use.
Two operators indicated
-
that they would operate different coolers than the
-
EOP writer indicated should be operated at this
_
step.
_
b.
Table 4:
The-alarm values for 2E11N009A and 2E11NOO9B were listed as 175 Degrees. The Unit 1
'
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-instruments were set at 150 Degrees.
Additionally, there were differences between the calibration
. procedure and the instrument settings in the field listed below:
-
2E11N600A 2E11N600B 2E41N600 2E41N602A 2E41N602B 2E51N602A l
2E51N602B 2E51N603A 2E51N603B 2E51N603C 2E51N603D 2E11N601A 2E11N601B 2E51N604A 2"51N604B 2E51N604C 2E51N604D 2G31N602A
_
R
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__-
---meni---mm-----
ammmmmim= = =
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' Appendix B
2G31N602B 2G31N602C 2G31N602D 2G31N602E 2G31N602F 1E11N600A 1E11N600B 1E41N600 1E41N602A 1E41N602B-1B21N603 c.. Table 4:
The licensee originally indicated that the
'
Maximum Safe Operating values were set using EQ maximum peak temperatures; however, the team found
)
that the MSO values did not always agree with the EQ
,
maximum penk temperatures.
One example was i
identified where the values agree.
The Main Steam _
l Line MSO temperature was 300 Degrees and the EQ peak j
value was listed as 300 Degrees.
A number of other I
examples were identified where the values did not agree.
These included the following.
The HPCI Maximum Safe operating values were listed as-212.5 Degrees.
The EQ peak value was 245 Degrees.
The RCIC MSO temperature was listed as 212.5, but the EQ Maximum peak temperature was 311 Degrees.
These
.
values need to be reviewed for consistency.
'
d.
Tat ie 5:
The high alarm setpoints given for 2T45-N007 and 2T45-N006 were list (d as 51 inches in the table.
The ARPs listed the values as 52 inches.
i The inconsistency between the ARPs and the EOPs i
should be evaluated.
.
e.
Table 5:
The high-high alarm setpoints given for
!
2T45-4005, 2T45-N003B, 2T45-N004, 2T45-N003A,-
2T45-N001, 2T45-N002A, 2T45-N002B, 2T45-N002C,.and
'
2T45-NOO2D were listed as 9 inches..The ARPs listed the values as 7 inches.
The alarm setpoint of 9 inches corresponded to the high-high-high setpoint.
The EOP or the ARPs should be revised to correct
'
this discrepancy.
5.-
31EO-EOP-102-2S-a, General comment:
Procedure nomenclature does not
!
match-label nomenclature on the control room panel for steps 3.1.8, 4.1,14, 3.3.4, 3.3.5, 3.4.5, 3.4.6, and 3.4.7.
b.
Step 3.1.2: This step does not contain the switch numbers to " Place HSIV control switches to closed".
c.
Step 3.1.6: This step does not contain the switch numbers to "Open outboard MSIVs".
d.
Step 3.1.15: This step directs the operator to defeat turbine bypass valve low main condenser vacuum interlock per Attachment 1 Section 3 as l
l
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,,,,,,, -,,,,,, -, -,, -, -, - - - - - - -
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Appendix B
necessary.
This step requires the operator to use a
._
screwdriver to lift leads to defeat bypass valve low
~
vacuum closure.
However, the control room EOP tool pouch did not contain a screwdriver to accomplish this task.
When this discrepancy was noted to the
^
licensee, the licensee took immediate corrective C
action to place a screwdriver in the tool pouch.
The licensee stated that the EOP tool accountability procedure would be changed to reflect the addition of the scrowdriver to the control room tool pouch.
6.
31EO-EOP-103-2S a.
General comment:
There were labeling deficiencies (i.e., the compor.cnt label did not match the EOP) in the following paragraphs of this EOP:
3.1.1, 3.2.5, 3.2.9, 3.6.5, 3.7.2, 3.7.3, and 3.7 4.
l b.
General comment:
There were unapproved operator aids (tape numbers) inside the plexiglass on the i
scram test switches on panel 2H11-P610.
7.
_
a.
Step 3.1.9.43 This step referred to differemdal pressure calculations in step 3.1.8.3.
There was no step with tnis number.
The correct reference 3.1.9.3 may be a more appropriate reference.
8.
31EO-EOP-10f-2S a.
General comment: Several nomenclature mismatches between procedure and control room equipment were noted. Component nur.bers were not included in the
=
procedure and component number s appeared in the procedure but were not present on control room placards. Examples appear in steps 3.4 and 3.7.
9.
31EO-EOP-107-2S a.
General comment:
Numerous procedure steps did not match label nomenclature on the control room panel, i.e. stop 3.1.2: this step required the operator reset HPCI isolation signal A(B) whereas the cWitch is labeled " Auto" isolation.
Step 3.2.6 describes valve 2E41-F003 as HPCI Eteam Line Icol V1v; panel label reads Outbd Steam Isol Vlv.
b.
Step 3.1.4 This stop does not contain the switch number for starting HPCI vacuum pump and step 3.1.8 m
does not list the switch for the Auxiliary 011 Pump.
,
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_ _ _ _ _ - - - _ _ _ _ _ _ _ _. _ - _ - _ _ _ _ _ _ _ _ _ _ - _
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Appendix B
10. 31EO-EOP-108-2S a.
General comment:
There were labeling deficiencies (i.e., the component label did not match the ECP) in the following paragraphs of this EOP (these are only examples and are not all inclusive of the deficiencies observed):
3.2.3, 3.2.4, 3.2.5, 3.2.7, 3.2.9, 3.2.10, 3.3.2, 3.3.6, and 3.3.6.
11. 31EO-EOP-109-2S a.
General comment: Items similar to f. through j.
below exist in the component system operating
'
procedures for CRD and HPCI methods of alternate boron injection, b.
Step 3.1.2.3: This step directs the plant operator to de-energize SBLC heat tracing by turning off i
breakers 3 and 11 and provides 2R24-S037 as the
implied location for these brer,kers.
The location i
of breakers 3 and 11 is not readily apparent from viewing the panel.
The actual location of breakers
!
3 and 11 is in 2R25-S107 which is located within panel 2R24-S037.
.'
c.
Step 3.1.3.1: This step states "At panel 2G31-P001 (185RBR25) close Procoat Pump Suction Valve 2G31-l F106."
Two operators were aeked to locate the switch to close the prevvat romp suction valve.
One
,
operator could not find the switch, but finally
decided to look inside the ph.sl, the other operator i
stated if he could not find a 6 witch he would look inside the panel.
The valve position indicating i
light label on the panel and the switch label within
)
the panel read " tank outlet" vice " pump suction" as I
specified within the procedure.
l
d.
Stops 3.1.3.5 and 3.1.3.6 These steps require the l
plant operator to remove a level switch from the precoat tank and to install a mating flange with an isolation valve and hose connection.
The location of the necessary tools and equipment is not specified, i.e. stored in 185' or 130' EOP gang box.
c.
Stops 3.2.3.13 and 3.3.3.13: Those steps did not road " Maintain level in Procoat tank with 2G31-F088 as needed while filling and venting hoses" and were
,
not placed after steps 3.2.3.11 and 3.3.3.11
!
respectively, f.
Prior to step 3.3.2.1: The SBLC combined drain valve 2C41-F034 is not confirmed to be closed prior to
-- ___ _______ __ _ - ____-_ ___. _ _ _ _ - _ _ - - _ _ _
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Appendix B
attaching hose assembly at outlet of F034 in step 3.3.2.1.
This action is taken in 34SO-E51-001-2S (alternate boron injection using RCIC) steps 7.3.7.7.1 and 7.3.7.7.2.
=-
'
The caution statement after step 3.3.2.1:
This caution concerning the hose pulling apart is not included in procedure 34SO-E51-001-25.
h.
Step 3.3.2.4 and 3.3.2.5: These steps require the operator to install a plug in one floor drain and i
ensure the other drain is open prior to establishing
-
a level of 6 inches to 18 inches in the SBLC area enclosure.
34SO-E51-001-2S requires the operator to ensure "both" floor drains are open.
1.
Step 3.3.2.6 This step requ!ies the operator to de-
!
energize the SDLC piping heat tracing by turning off L
designated breakers; 34SO-E51-001-2S does not include this step.
j.
Step 3.3.2.13: This step requires the operator to
-
unlock and open SBLC drain valve F041.
[
001-2S step 7.3.7.7.6 requires the operator to
.
'
" confirm open" vice unlock and open F034.
-
12. 31EO-EOP-110-2S a.
General comment:
The nomenclature for numerous procedure steps did not match label nomenclature on the control room panel, i.e.,
step 3.1.1.3: this step had the operator confirm closed several valves.
!
-
The procedure identifies valve 2E31-F048A(B) as Ht i
Exch Side Byp Valve; the label on the control panel indicates HX Bypass V1v.
The procedure indicates valve 2E11-F068A(B) as Ht Exch Side Disch Valve; the control room panel indicated this valve to be HX Disch Vlv.
i
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13. 31EO-EOP-111-2S a.
General comment:
There were deficiencies in labeling (i.e., the component label plates did not match the EOP) in the following paragraphs of this EOP:
3.1.1, 3.1.6, 3.1.7, and 3.1.9.
14, 31EO-EOP-112-2S
a.
General comment: Several nomenclature mismatches between p*ocedure and control room equipment were noted. Compot.cnt numbers were not included in tho
-
procedure and component numbers appeared in the
_. _......
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c.
.
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Appendix D
procedure but were not present on control room placards. Exampics appear in steps 3.1.1.4.1, 3.3.5, 3.4.5.
b.
Step 3.7.3 substeps 2 and 3:
These steps required the operator to determine primary containment level and drywell pressure respectively.
There are
numerous methods and indicators that can be used.
A summary list of acceptable methods / indicators was not included as a memory aid to the operator.
.
15, 34SO-E11-010-2S a.
General comment:
The suppression pool was referred H
to as both the suppression pool and the torus at various points in the procedure.
The reference to this system was not consistent.
This also does not match the labeling on the control room panels which refer to the torus, b.
Steps 7.2.5, 7.4.7.4.1, and 7.4.7.5.1:
These steps can be entered from the steam condensing mode of
'
The conditions for entry from this mode was not included in these steps.
16. 34SO-E21-001-2S a.
Stop 7.4.2.3 This step required the operator to confirm that the CST level was greater than 15 feet.
The definition of confirm was "if it is not that way make it that way".
Without BOP power available the operator would be unable to fill the tank if the level was low.
The demineralized water storage tank transfer pumps are powered from DOP sources.
j b.
Step 7.4.3.4:
This stop required the operator to confirm that the CST level was greater than 25 feet.
The definition of confirm was "jl it is not that way make it that way".
Without Bor power available the operator would be unable to fill the tank if the level was low.
The demineralized water storage tank transfer pumps are powered from BOP sources.
c.
Steps 7.4.2.4, 7.4.2.7 and 7.4.3.7:
These steps contained an infrequently operated valve that required local operation.
The valve location and the fact that the valve required local operation should have been included in those steps, d.
Section 7.4.2 and 7.4.3:
These sections could not be accomplished as written if BOP power was not available.
Specifically, the AOVs fail open and the p t~-
-
.~,.g i-9,
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.
Appendix B
valves cannot be operated from the control room to perform the required isolation function.
-
,
17. 34SO-P33-001-2S a.
General comment:
Throughout this procedure H202 (Hydrogen Peroxide) was used to identify Hydrogen l
and Oxygen.
The better nomenclature may have been H2 and 02.
b.
General comment:
There were labeling deficiencies (i.e., the component label did not match the EOP) in the following parag'taphs of this EOP 7.2.1, 7.2.4.1, 7.2.4.3, 7.2.5.1, 7.2.5.3, 7.3.3, and 7.3.4.
L c.
Step 6.53 This step listed a primary containment
'
H2O (water) analyzer.
This step may have more appropriately referred to a primhry containment H2 and 02 analyzer.
d.
Steps 7.1.1, 7.2.2, 7.3.1 and 7.3.2:
These steps referred to a mode switch on 2P33-P601A.
There was no mode switch on-this panel.
The steps may have more appropriately referred to a selector switch.
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APPENDIX C Details of SER and Human Factors Concerns I.
HF Concerns The inspection team found no new human factors items of concern other than the labeling / nomenclature concerns discussed in Appendix B.
II. SER - WG Comment Resolutions All SER WG comments have been adequately addressed through dc/olopment of the new EOP WG (WG-11) or the comments are no longer applicable as a result of the new Revision 4 EOPs and supplemental procedures.
III.SER - V&V and Training Comment R3 solutions 1.
SER item C.2.a:
a.
This item stated that the PGP should be expanded to include the critoria for selection of the verification team and clearly identify their roles and responsibilities, A new verification proceduro was written which roc'uired a multi-disciplined team consisting of, as a sinimum, human factors engineering, EPG generation, EOP generation, and Operations personnel.
2.
SER item C.2.b e.
This item stated that the PGP should be expanded to include a clear explanation of what criteria would indicate a need for involvement of a team of exports from other disciplines and what capabilities they
,
should possess.
A now validation procedure has been written which accomplished this task.
,
3.
SER item C.5 a.
This item stated that the V&V program proposed by
'
the licensee was adoquate, but that procedures 30AC-OPS-006-OS and 30AC-OPS-003-PS needed to be
reviewed.
The team reviewed these procedures and found that they were adequate.
4.
SER item C.6.a:
a.
This item stated that section 3.7 of the PGP, pages 17-21, did not incorporate the response and it should be expanded accordingly.
This item had been corrected.
l l
l
)
...%
a a'
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Appendix C
5.
SER item C.6.bt a.
Thir, item stated that the PGP should include the e*propriate criteria for determining the type of f
validation required.
The walkthrough validation method has been incorporated into the current procedure which will be used for validation of the procedures that cannot be validated on the simulator.
The table top method will only be used when no other method is available.
6.
SER item Dt a.
The SER stated that the PGP did not address directly the issue of minimum shift complement required by the Technical Specifications.
The PGP requires that all EOPs be written such that they can be performed by a Technical Specifications minimum crew size.
The licensee has elected to train their operators with a crew that is one greater but which is more representative of expected accident conditions.
The team observed simulator scenarios and reviewed the licensee's PGP section 3.2.
They found staffing levels to be both consistent with current training practices and adequate for efficient use of the EoPs in mitigating accidents.
IV. SER-PGP Comment Resolutions 1.
Paragraph 1.a (page 8)
a.
This item reported that the WG (subsection 8.1.C 3.2) should be revised to define the phrase
"other actions as determined necessary" in providing requirements for EPMs.
The WG no longer addresses
'
EPMs.
The new section of the WG concerning supplementary EOPs does not include a phrase similar to the above.
2.-
Paragraph 1.b (page 9)
!
a.
This item reported a problem concerning section access of EPMs and also addressed the need to l
standardize where entry conditions are maintained so L
that they are readily visible to the operator.
'
were no longer being used by the licensee.
The entry conditions for supplementary EOPs only required entry as directed by_the flow chart I
...Q
.f.
- c's
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Appendix C
i 3.
Paragraph 1.c (page 9)
a.
This item repci-tcd that the WG did not provide specific criteria for 1.ine spacing to enhance legibility of the flow charts.
Review of this item determined that the WG still did not provide this criteria, however, the readability of the new flow charts was greatly enhanced.
This Itum is closed.
4.
Paragraph 1.d (page 9)
a.
This item reported a lacP. of controls in the WO over the use of capitalization.
Review of this iten determined that capitalization requirements were included in paragraph 2.11 af the new WG.
5.
Paragraph 1.c (page 9)
a.
This item reported that the WG did not requi?le units of measure in EOPs to match the units of measure on plant instrumentation.
Review of this item determined that paragraph 2.5 of the new WG required EOP units to match the plant instrumentatien units.
,
6.
Paragraphs 2.a through 2.d (page 9)
a.
These paragraphs provided administrative comments on the organization of the PGP package.
The PGP at Hatch was rect a living document.
The PGP was specifically put together from other conttviled
'
documents for a one time submittal to the NRC.
Each of the individual documents was revised as necessary to provide required controls, but the PGP as a whole was not revised.
As a result the SER comments were not applicable.
The teau found this to be acceptabl,
gU e
Ti
.s
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APPENDIX D Abbreviations AOP Abnormal Operating Procedure AOV Air Operated Valve ARP Alarm Responso Procedure ATWS Anticipated Transcient Without scram BWROG Boiling Water Reactor Owners Group CP Containment Primary i
CRD Control Rod Drivo l
EOP Emergency Operating Procedure l
EPG Emergency Proceduro Guidelines EPIP Emergency Plan Impicmenting Procedure EPM End Path Manual EQ Environmental Qualifications
!!F
}!uman Factors llPCI liigh Pressure Coolant Injection IFI Inspector Followup Item IR
Inspection Report
Loss of Coolant Accident
Low Pressure Coolant Injection
!
NRC
Nuclear Regulatory Commission
l
OP
Operating Procedure
'
Proco(ure Generation Package
PSTG
Plant Specific Technical Guidelines
Quali':y Assuranco
Reactor Coro Isolation Cocling
Ri!R
Residt.al llent Removal
Roactor Pressure Vossol
SBLC
f
Safety Evaluation Report
!
Standby Gas Treatment
Safoty Relief Valve
Vorification & Validation
WG
Writer's Guido
i
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t