IR 05000010/1976011
| ML19340A740 | |
| Person / Time | |
|---|---|
| Site: | Dresden  |
| Issue date: | 07/15/1976 |
| From: | Johnson P, Knop R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML19340A736 | List: |
| References | |
| 50-010-76-11, 50-10-76-11, 50-237-76-14, 50-249-76-12, NUDOCS 8009030762 | |
| Download: ML19340A740 (23) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
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OFFICE OF INSPECTION AND ENFORCEMENT
REGION III
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Report of Operations Inspection
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IE Inspection Report No. 050-010/76-11 IE Inspection Report No. 050-237/76-14 IE Inspection Report No. 050-249/76-12 Licensee:
Commonwealth Edison Company P. O. Box 767 Chicago, Illinois 60690 Dresden Nuclear Power Station License No. DPR-2 Units 1, 2 and 3 License No. DPR-19 Morris, Illinois License No. DPR-25 Category:
C Type of Lice.:see:
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Type of Inspection:
Routine, Unannounced Dates of Inspection:
May 12-14, 17-18, 20-21, 25-27, and June 1-2 and 10, 1976 Principal Inspector:
.H.Jobnsong uj oe 7[/ /
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Accompanying InLpector:
R. C. Knop (June 2, 1976)
Other Accompanying Personnel: None R. C. Knop, A C '
7</n/74
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Reviewed By:
Chief Reactor Projects Section 1 (Date)
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SUMMARY OF FINDINGS
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Inspection Summary
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Inspection on May 12-14, 17-18, 20-21, 25-27, June 1-2, and 10, (Unit 1, 76-11: Unit 2, 76-14; Unit 3, 76-12): Review of requalification train-ing, licensee's actions in response to IE Bulletins and previous noncom-
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pliance items, Unit 2 startup activities, and significant operating events which occurred (Unit 2 only) during the inspection. Two Unit 2 noncom-pliance items were noted, related to implementation of maintenance pro-cedures and performance of required surveillance tests.
Enforcement Items The following items of noncompliance were identified during the inspection:
A.
Infractions 1.
Contrary to Paragraph 6.2.A.6 of the Dresden 2 Technical Specifications, portions of the approved reactor vessel head installation procedure which (1) require documentation of stud elongation readings and comparison with expected values and (2) specify the use of each tensioner for specific studs
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vere not followed during reactor vessel head stud tensioning
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on May 12, 1976.
(Paragraph 5.b, Report Details)
2.
Contrary to Paragraph 4.5.A.3 of the Dresden 2 Technical Specifications, LPCI pumps and motor operated valves were not tested for operability between April 11 and June 1, 1976.
(Paragraph 5.c, Report Details)
B.
Deficiencies
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None.
Licensee Action on Previously Identified Enforcement Items This inspection included review of licensee actions in response to several enforcemint letters (Paragraph 10, Report Details). All items reviewed were considered resolved except the following:
A.
Maintenance of jumper logs requires further improvement.
(Para-graph 104. (1), Report Details)
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B.
Improvements to the IF-300. fuel cask handling procedure to assure
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documentation of temperature and leak test data were in progress.
(Paragraph 10.h. (4), Report Details)
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Other Significant Items
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A. -
Systems and Components -
1.
An inadvertent injection of sodium pentaborate into the Unit 2 reactor occurred on May 19, 1976.
(Paragraph 8, Report Details)
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2.
The Unit 2 reactor started up on May 23, 1976, after completing a refueling outage. Commercial operation resumed on May 26, 1976.
(Paragraph 5, Report Details)
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3.
A Unit 2 relief valve failed to close following a test actuation
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on May 25, 1976, resulting in depressurization of the reactor l
to approximately 175 psig.
(Paragraph 6, Report Details)
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Unit 2 experienced an apparent off-gas detonation on June 7, 1976.
(Paragraph 9, Report Details)
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Facility Items (Plans and Procedures)
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Managerial Items The licensee announced changes in station organization which included
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reassignment of the Maintenance Engineer.
(Paragraph 3, Report
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i Details)
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D.
Noncompliance Identified and Corrected by Licensee
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None.
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Deviations
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None.
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F.
Status of-Previously Reported Unresolved Items
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Onsite receipt inspection procedures had been revised to provide I
for inspection of.all safety-related materials received at the
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station.
(Paragraph 12.d, Report Details)
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2.
Administrative procedures had been revised to (a) delete out-i.
dated: references to SRB, etc., and (b) provide a cross reference between_ procedures.
(Paragraph 12.e,ReportDetails}
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Management Interview
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The inspectors conducted a management interview uith Messrs. Stephenson (Station Superintendent), Roberts (Assistant Superintendc. -), and other (N members of the station staff at the conclusion of the inspeu-ion on
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June 2.
The following matters were discussed:
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A.
The licensee was advised that the Operator Requalification Program had been reviewed and found to be functioning effectively, with the qualification that the review did not include evaluation of technical
content. The inspector noted that a few management personnel were
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delinquent on completion of required reading and that, in addition, i
incorrect certifications to the Operator Licensing Branch had been
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made in four cases. The licensee stated that a letter would be
forwarded to the Operator Licensing Branch by July 1, certifying that the individualsinvolved had reviewed all phanges in facility g
design, procedures, and licenses.
The letter-was issued sub-sequent to the inspection.
(Paragraph 4, Report Details)
B.
The inspector stated that he had conducted a followup review of licensee actions identified in responses to several enforcement letters, and that all but two noncompliance items were considered to have been resolved (Paragraph 10, Report Details). Related comments were as follows:
1.
Review showed jumper logs to be in need of further improvement.
Three recent entries in the Unit 1 jumper log were lacking verification signatures, and several long-standing jumper entries
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were still noted to be present in the Unit 2 and 3 jumper logs. The licensee stated that:
(1) a review of all jumper logs would be conducted, (2) work requests or modifications would be initiated where necessary to eliminate jumpers of a permanent nature, and (3) jumper log procedures would be reviewed to identify needed improvements, these actions to be completed by July 1,1976. The inspector stated the improvements in jumper log procedures should assure that the identity of individuals placing and verifying jumpers is retained in the jumper log until the jumper is removed.
(Paragraph 10.d. (1),
Report Details)
2.
Revision to the IF-300 fuel cask handling procedure to assure documentation of temperature and leak test data was noted to be in progress, with completion of this item to be verified during a future inspection.
(Paragraph 10.h.(4), Report Details)
3.
A previous noncompliance item concerning documentation of the
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Unit 3 hydrostatic test following the 1975 replacement of the recirculation bypass piping was considered to have been resolved.
The inspector noted that the inadvertent increase in' reactor pressure to approximately 1250 psig, although subsequently reviewed
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as required by Technical Specifications, appeared to warrant
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further consideration in view of the small margin to a Technical Specifications safety limit which remained. The inspector noted that the shutdown cooling heat exchanger relief valves apparently were not adequate _to prevent overpressurization in such situations.
( 3, lie noted that ASME Section XI apparently does not require over-
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pressure protection during hydrostatic tests, but suggested that appropriate precautions be considered to prevent possible overpressurization as a result of inadvertent isolation of a si,ngle pressure instrument. The licensee acknowledge the inspec-tor's comments.
(Paragraph 10.h.(5), Report Details)
C.
The licensee was informed that completion of required actions for RO/IE Bulletins 74-09, 74-13, 74-14, and 75-03 had been verified (Paragrag)toIEBulletin76-01hadbeenreviewedandthat 11, Report Details).
The inspector stated that the definition response-of further actions appeared to be necessary.
(Paragraph 11.e, Report De te ' Is). After discussion of this matter, the licensee agreed to the following commitments:
1.
Procedures for emergency / isolation condenser tube leak will be revised by July 15, 1976, to provide more specific guidance to operating personnel on action levels and corrective actions. This review will include evaluation of emergency / isolation condenser vent monitor performance to determine (1) whether the present set-points are meaningful and (2) what indicated levels are consider-ed to be indicative of a tube leak.
The licensee also stated
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during a subsequent telephone conversation that daily surveillance logs would be revised to require recording of actual shell side
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temperature and level (recording of these values was 3.ated to be standard practice, although the surveillance log required only that the parameters by verified within established limits).
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2.
The licensee will initiate a program to provide for periodic activity sampics of emergency / isolation condenser shell side water. These samples will be taken biweekly through the end of 1976 or until the inspector concurs that a satisfactory base level has been established, and thereaf ter at monthly intervals.
Procedures will also require that a shell side activity cample be taken following initiation of condenser opetation and when-ever a leak is suspected. A licensee representative stated during a subsequent telephone conversation that the sampling program would commence on August 1, 1976.
D.
The inspector summarized 3ls review of activities related to the Unit.
startup, including noncompliance items related to impicmentation of the
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reactor vessel head installation procedure and omission of LPCI pump i
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and motor operated valve operability tests. The inspector noted
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that prompt corrective actions had been taken with respect to reactor vessel stud tensioning activities.
The licensee stated that the sub-ject of adherence to operating, maintenance, and othcr procedures would (
be included in an interview program being planned for all station per-
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sonnel. The licensee further stated that this program would be com-pleted by July 1, 1976, for management (non-union) personnel, and would proceed through the summer for non-management personnel.
The inspector stated that in view of the corrective actions taken and identified by the licensee, a formal response to the noncompliance item related to main-tenance procedures would not be required.
(Paragraph 5, Report Details) '
E.
The failure of the Unit 2 Target Rock relief valve to close following testing was discussed. The inspector noted that the situation appeared to have been handled properly by station operators. The licensee stated that consideration was being given to the performance of a nitrogen leak test of all Target Rock relief valve pilots during each refueling outage. This intention was confirmed in the licensee event report which followed.
(Paragraph 6, Report Details)
F.
The licensee confirmed the inspector's understanding that a 30-day report would be submitted concerning the failure of the Units 2 and 3 reactor building crane brake. The inspector also obtained from the licensee a com-mitment that the IE regional office would be informed before the slow speed hoist motor is used for fuel cask handling.
(Paragraph 7, Report Details)
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G.
The inspector noted that most of the Barton DP switches identified in
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an earlier licensee letter had been replaced, although the schedule on remaining switches was unclear. The licensee stated that a letter updating the status of the commitment would be forthcoming.
(Paragraph 12.b, Report Details)
A brief telephone interview was conducted with Mr. Stephenson following an additional site visit on June 10 to review an apparent off-gas detonation in Unit 2.
The inspector stated that: (1) the earlier commitment to improve the "Off-gas Explosion" procedure should recognize that symptoms and required actions may differ considerably for different operating modes of the off-gas system and (2) the addition of special instrumentation could be advantageous in the evaluation of any possible future off-gas detonation.
The 11:ensee concurred with the inspector's comments.
(Paragraph 9, Report Details)
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,PV? ORT DETAILS 1.
Persens Contacted (.s'
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B. Stephenson, Station Superintendent A. Roberts, Assistant Superintendent J. Abel, Administrative Assistant D. Adam, Radiation / Chemistry Supervisor J. Bell, Maintenance Planner a
G. Borean, Chemist A.
Engineering Technician (Training Department)
T sen, Shift Engineer Leading Nuclear Engineer burg, Maintenance Staff Assistant
, Maintenance Foreman irmeyer, Shift Engincar W. nildy. Instrument Engineer J. Jurecki, Maintenance Staff Assistant J. Kolanowski, Unit 2 Leading Engineer C. Lawton, Office Supervisor C. Maney, Procedures Coordinator D. Maxwell, Quality Control Inspector E. Mazur, Outage Planner R. Meadows, Quality Control Engineer
L. Noreng, Chemist B. Nelson, Radiation - Chemistry Technician J. Pearson, Nuclear Station Operator
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R. Ragan, Unit 3 Operating Engineer G. Reimers, Unit 2 Engineer W. Roman, Shift Engineer (Training Department)
s C. Sargent, Unit 3 Leading Engineer C. Schiavi, Modifications Coordinator N. Scott, Unit 2 Operating Engineer J. Toscas, Nuclear Engineer T. Watts, Technical Staff Supervisor R. Weidner, Procedur'es Coordinator B. Zank, Training Supervisor W. LaCorte, Target Rock Company Representative 2.
General Units 1 and 3 were operating at the time of this inspection. Unit 2 was in the process of completing a 10-week refueling outage and resuming commercial operation.
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3.
Organization Station managment informed the inspector by telephone subsequent ('
to the inspection that certain personnel changes were being announced
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effective June 21, 1976. These included: (1) reassignment of E. Meintel to an off-station maintenance position, (2) assignment of J. Eenigenburg as Maintenance Engineer, (3) assignment of G. Frankovich and J. Bell to the, newly created positions of Master Electrician and Master Mechanic, respectively, and (4) assignment of R. Kyrouac as Quality Control
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Engineer.
4.
Requalification Training The licensee's operator requalification program was reviewed to deter-mine whether the program was being conducted as required by the approved retraining program and Appendix A to 10 CFR 55.
The review included discussions with Training Department representatives and examination of lecture schedules, attendance records, directives establishing on-the-job training requirements, records of procedure and required reading reviews, and selected individual training records.
The review showed conduct of the training program, maintenance of train-ing records, and licensee evaluation of licensed operators to ha 1.n accordance with the approved retraining program. The inspector made the following comments regarding licensed operator review of design changes, procedures changes, and changes in facility licenses:
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'To assure licensed operator review of changes in procedures,
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a.
facility design, and facility licenses, the licensee has established a required reading program. This involves the place-ment of a weekly required reading package in strategic locations (e.g., Control Room) for review and sign-of f by each individual.
Examination showed the program to be working effectively, with records indicating current review status for over 90% of the licensed personnel. However, records indicated that a small number of individuals, all holding SRO licenses, had not reviewed requir6d reading for extended periods of time ranging to several months. Training Department representatives stated that they had been unsuccessful in efforts to have these 1-dividuals complete their required reading. The inspector 6:ated that such individuals should be brought to the attention of station management for resolution.
It was noted prior to the completion of the inspection that formal notifications had been sent by the Training Department to the individuals involved.
b.
Training records indicated operator license renewal applications to have been submitted in recent months for four of the individuals found to be delinquent in required reading. These applications
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included a statement that the individual had reviewed all changes
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l in facility design, procedures, and licenses, although this
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statement was not supported by retraining records. A licensee ([)
representative-stated that this certification had been based
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r on review of a catch-up required reading package compiled to show all changer. for the two-year period ending in June 1975
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(as a result of inadequacies identified during audits by IE
and Operator Licensing), and that records of subsequent weekly reIquired reading had not been checked. This matter was dis-
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cussed further during the management interview.
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'5.
Review of Plant Operations (Post-Outage, Unit 2)
The Unit 2 refueling outage ended with a reactor startup on May 23, and the unit resumed commerical operation on May 26, 1976. A review j
was conducted to determine whether activities associated with the-return of Unit. 2 to an operating condition were performed in accord-
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ance with established requirements. The review included:
(1) observa-tion of portions of reactor vessel head installation, reactor vessel hydrostatic test, and post-maintenance reactor coolant relief valve
tests; (2) review of pre-startup checks performed on nuclear instrument-ation; (3) examination of the approved control rod sequence; and
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(4) examination of documentation of selected surveillance tests per-formed during the refueling outage. The following commente resulted from the review:
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a.
On May 25, 1976, the inspector was advised by the licensee that
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the 2A (Target Rock) relief valve had failed to close following a test actuation earlier that day. This event is discussed further in Paragraph 6.
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b.
During observation of reactor vessel stud tensioning on May 12,
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it was noted that certain portions of the stud tensioning procedure were not~being followed. Discrepancies noted were:
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(1) two procedure steps required repeat of other procedure steps which did'not exist, (2) stud elongation readings were not being taken as required, (3) maintenance personnel were not
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assuring that observed stud elongation agreed with predicted i-elongation within prescribed tolerances, and (4) a procedure i
step specifying that each tensioner be used only on certain studs was not being adhered to.
The inspector informed station
management that the approved pror.edure was not being followed
and noted that this represented noncompliance with Section 6.2.A-of the Technical Specifications.
Subsequent review of the com-
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pleted procedure showed that:
(1) temporary changes had been 1-issued where required, (2) omitted stud' elongation readings
and all readings subsequent to the identification of, noncompliance had been recorded, and (3) all final stud elongations were
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within the required range. Station management also described an employee interview program which was scheduled to cover several matters of interest with all station employees. The licensee stated that these interviews would include discussion 7g(
of adherence to operating and maintenance procedures, and that
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the interviews for a11 management (non-union) personnel would be completed by July 1,1976.
Interviews for non-management personnel were to continue through the summer. The inspector stated that, in view of the corrective actions taken and plan-ned by the licensee, a response to the item of noncompliance a
wo'uld not be required.
c.
Documentation showed that surveillance tests to demonstrate LpCI pump and motor-operated valve operability had been performed on April 11 and again on June 1 following plant startup.
No record or log entry indicating performance of a test during the intervening period could be found.
paragraph 4.5.A.3 of the Technical Specifications requires that these tests be performed monthly. The inspector noted that noncompliance was evident since the interval between the tests exceeded the period of one month plus 25% allowed by Jaragraph 1.0.BB of the Technical Specifications.
6.
Fai~ ore of Target Rock Relief Valve to Close (Unit 2)
On May 25, 1976, following test actuation at a reactor pressure of
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approximately 925 psig, the 2A relief valve (the only Target Rock relief valve installed in Unit 2) failed to rescat when the hand
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switch was returned to the closed position.
Review of logs and other records and discussions with licensee representatives provided thefo}
(a Licensee Event ReportJowinginformationconcerningtheevent was subsequently submitted to the NRC):
a.
Initial Conditions - At the time of the event, the reactor was critical at 15 - 20% power. Steam flow had been estab-lished through,the turbine bypass valves to the condenser with three bypass valves open and a fourth valve approximately one tenth open. The unit generator was not connected to the licensee's distribution system.
b.
Sequence Time Event 0251 2A relief valve failed to reseat after test actuation.
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Various attempts made by operator to close the
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switch and by lowering turbine throttic pres-sure to 900 psig (reactor pressure remained
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above 875 psig).
0258 Torus high level alarm, still trying to close relief valve.
0303 Manually scrammed reactor, placed mode switch in shutdown.
0310 Closed MSlV's; initiated torus cooling using three LPCI pumps.
0345 Relief valve reseated at a reactor pressure of approximately 175 psig.
(Time of valve closure estimated from recorder information).
c.
Analysis of Event - The inspector concurred with the licensee's conclusion that the reactor vessel cooldown rate had not exceeded Technical Specifications limits. Recorder charts showing recir-culation loop temperatures indicated total cooldown during the first 30, 60, and 90 minutes following the scram to have been 118, 143, and 158 F, respectively.
Paragraph 3.6.A.2 of the
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Technical Specifications allows a step reduction in reactor cool-
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ant temperature of 240 F so long as the shell flange to shell temperature differential does not exceed 140 F.
Recorder charts indicated the shell flange to shell temperature differentici to have remained below 50 F.
A licensee representative stated that
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internal and external torus inspections showed no apparent damage.
The inspector's review showed operator actions following the relief valve failure to have been consistent with Procedure DOA 250-1, " Relief or Safety Valve Stuck Open,"
d.
Cause of Failure - Tests performed by the licensee under the direction of a vendor representative showed pilot and second stage valve leakage to be excessive.
In particular, continuous flow through the pilot valve was observed at a nitrogen pressure of approximately 100 psi; the vendor's recommended limit is 100
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bubbles per minute at a nitrogen pressure of 1020 psig. The licensee concluded that this leakage, although not adequate to cause the valve to lift, was sufficient to prevent rescating of the second stage valve once actuation had occurred.
Examination of the pilot valve stem showed a significant amount of steam cutting to have occurred. Leakage of the second stage valve did not appear to a causative factor.
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Corrective Action - The pilot valve and second stage valve assemblies were replaced under the direction of a vendor repre-sentative.
Following an On-site Review of the event and corrective actions, Unit 2 was started up and the relief valve was satis-(
factorily tested at 150 psig. The inspector also observed satisfactory test actuation of all relief valves at 925 psig
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on May 26 before Unit 2 resumed cornaricel operation. The licensee's report of the occurrence stated that the pilot stage of the Target Rock relief valves would be leak-tested during future refueling outages.
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7.
'Jnits 2 and 3 Reactor Building Crane Brake Malfunction On May 11, 1976, while the reactor building crane was being used to inatall the Unit 2 reactor vessel head, the head dropped abruptly approximately 15 inches before the brake engaged. A second abrupt drop was observed before the head was seated on the reactor vessel flange. Both drops occurred as the head was being guided down over the reactor vessel studs, with thread protectors installed on selected studs being used as guides.
No forcible contact with the flange or studs occurred, and no damage resulted to either the crane or reactor components. Review of electrical circuit diagrams and discussion of the event with licensee representatives disclosed the following information:
a.
Each drop was noticeably abrupt; i.e.,
appeared to be essentially a free fall until the brake engaged.
The brake appeared to operate
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properly upon engagement, promptly decelerating the head to a
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stationary position without apparent jerking or binding.
b.
A recently completed crane modification included the addition of an AC-powered " inching" motor to drive the hoist at a slower
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speed when handling a fuel shipping cask. An additional con-tactor assembly, operated by a relay in the inching motor control circuit, was added in parallel with the initial brake contacts.
The new contactor assembly consists of four contacts in a series-parallel arrangement to provide adequate current-interrupting capacity.
The licensee's investigation of the malfunction showed that the new contactor assembly functioned properly as long as both parallel contacts interrupted current at the same time.
Occasionally, however, the contacts did not open at the same time, leaving one contact to interrupt current flow to the brake sole-noid, which the contact was not capable of doing.
c.
After identifying the new contact assembly as the cause of the brake malfunction, the licensee removed the inching motor and related controls, including the new contact assembly, from service. Approval was received from NRR to proceed with scheduled
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fuel shipments with the inching motor and certain other portions of the crane modification removed from service. A licensee representative also stated during the management interview that the IE region 71 office would be informed before the inching motor is used for handling an irradiated fuel cask.
The licensee
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also stag 7 that a 30-day report would be submitted; this was d
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received-subsequent to the inspection.
8.
Sodium Pentaborate Injection (Unit 2)
i The licensee informed the inspector on May 19, 1976, that an inadvert-ent injection of sodium pentaborate into the reactor vessel had occur-red following successful completicn of the standby liquid control system injection test earlier that day.
The-licensee representative stated that system realignment had been temporarily halted at a point in the procedure which lef t SBLC pump suction and discharge valves open, and that 16% of the tank contents (approximately 625 gallons) had drained into the reactor vessel because of the higher elevation of the tank. The initial sample of reactor vessel water showed 380 ppm boron.
Feed and bleed and several drain-fill cycles reduced the boron concentration to 29 ppm the following morning.
Subsequent cleanup using three successive reactor water cleanup system deminer-alizer beds reduced the boron concentration to less than. ppm at about 12:00 p.m. on May 21, 1976.
Subsequent cleanup system operation reduced the concentratica to less than 0.1 ppm, which was stated by a chemist to be the approximate sensitivity of the titration
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(two drops of titrant).
Coolant samples taken on the mornings of May 26 and 27 showed no detectable boron concentration. Licensee
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representatives identified changes which would be made to the SBLC injection test procedure to prevent recurrence.
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9.
Of f-Gas Detonation (Unit 2)
The licensee informed IE:III on June 8,1976, that the rupture diaphragm on the "A" air ejector had blown at about 6:00 p.m.
the previous day.
One man in tha plant was stated to have heard a " thump", and an of f-gas detonation was believed to have occurred. The recombiner-charcoal system was in operation at the time, and the unit was operating at a steady load of 780 MWe.
The licensee stated that the only apparent perturbation to system operation was possible lifting of the air ejector steam supply relief valve. Reactor power was reduced following the detonation, the "B" air ejector was placed into operation, and plant load had been restored to 700 MWe by midday on June 8.
On June 9, the licensee informed IE:III that further examination of the off-gas system had shown the "B" steam jet air ejector rupture disc to be.
broken. At this time Unit 2 was operating at 750 MWe with the "B" SJAE in service. The recombiner booster jet was keeping a negative 4/ RO 50-237/76-32, dtd 6/10/76.
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pressure on this section of off-ga4 11nc however so that air flow i
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through the broken rupture disc was into the off-gas system. The licenseu representative stated later that a piece of sheet metal had been laid over the rupture disc to block the flow of air into the system. An additional site visit was made on Juaa 10 to review the (
off-gas detonation, uith observations as follows:
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a.
Observation of conditions in the "A" (standby) SJAE room disclosed no unusual conditions or apparent improper valve lineups, b.
Recorder charts showed stack monitor indications following the i
ev,ent to have increased by a factor of approximately two over a period of about 20 minutes, followed by a decrease to near the initia] level. Radiological aspects of the event were reviewed further by IE:III Radiation Specialists and will be discussed in a separate inspection repert. SJAE flow indication were not seaningful because of significant flow oscillations which resulted from difficulties experienced in placing the standby air ejector unit into service. Once the "B" SJAE was placed into service, flow indications stabilized and remained stable there-af ter, indicating no apparent subsequent event which could have broken the "B" SJAE rupture disc. Other recorder charts gave no indications as to the possible cause of the detonation.
c.
The operating mode of the off-gas system at the time of the detonation indicated that the detonation had probably been restricted to the volume between the SJAE's and the booster jet at the inlet to the recombiner. This is also indicated by observations
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reported by the licensee that: (1) no high pressure alarm was received in the 36-inch holdup line and (2) DOP tests after
_
the detonation showed the stack filters to have sustained no damage.
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The licensee stated that, as in the case of the April 29 Unit 3 off-gas detonation, an investigating team had been established to review the Unit 2 pet nati n.
The inspector noted that a previous inspection
report-had included a commitment by the licensee to revise Procedure DOA 5400-1, "Off-gas Explosion", to give more specific guidance to operators. He stated that this revision should cover dif ferent operating modes of the off-gas system, since symptoms and desired operator actions could differ fer different modes of off-gas system operation. The inspector also noted that additional instrumentation could help in the analysis and determination of cause in the event of a future detonation.
This was discussed further during the management in t e rview.
10.
Followup on Items of Noncompliance The review of licensee actions in response to previous items of noncom-pliance considered distribution and assignment of responsiblity for cor-rective actions, licensee review of noncompliance items and 5/ IE Inspection Rpt No. 050-249/76-07.
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corrective actions, and accomplishment of corrective actions and measures identified to avoid recurrence. This inspection included review of corrective actions outlined in licensee responses to ten enforcement letters, as follows:
a.
Response Dated September 6, 19746/
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Requirements governing the use of hand tools in Item A.3
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the reactor vessel were noted to have been incorporated into Unit 2/3 Refueling Procedure DFP 800-1.
Similar require-ments were observed to have been included in a draft of Unit 1
,
Procedure DFP 800-1 which was being readied for issue. Action 1:em record (AIR) 76-57 was tracking completion of the Unit i revision. Item resolved.
1!
b.
Reponse Dated April 17, 1975 Infraction No. 2 - Procedures identifying the review process for control rod sequences and providing direction for control
>
rod movements (principally DGP 3-4) were observed to have been provided. Additional instructions relating to control rod movements had also been incorporated into startup procedures.
Item resolved.
8/
c.
Response Dated May 9, 1975 (1) Deficiency No. 1 - The trend graph was verified to have
.
been " red lined" as indicated in the response.
Doctaenta-tion also showed that all instrument maintenance person-
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nel had reviewed the deficiency and the procedure which requires supervisory notificatian of unacceptable setpoints.
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Item resolved.
(2) Deficiency No. 2 - Review showed additional instructions to have been issued to operating personnel concerning this deficiency. These instructions call for indicating exceptions to the desired equipment lineup instead of changing the line-up required by the procedure.
Item resolved.
E d.
Response Dated May 20, 1975 (1) Deficiency No. 1 - Shift supervisor sign-of f for jumper log review was noted to have been added to the daily surveil-lance log as indicated in the response. However, review of the jumper log showed that three recent Unit 1 entries did not have verifications of jumper placement indicated.
Jumper logs for Units 2 and 3 included several older entries 6/ R0 Inspection Rpt No. 050-010/74-06.
- 1/ IE Inspection Rpt No. 050-249/75-06.
8/ IE Inspection Rpt No. 050-237/75-0.'.
9/ IE Inspection Rpt No. 050-010/75-05.
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dating back to 1972 which did not appear to be of temp-orary nature. Updating of the jumper logs was also being accomplished in sucn a way that the initials of those placing
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and verif*ying the placement of jumpers were not being retained. This previous noncompliance item was discussed
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during the management interview and will be reviewed further during a future inspection.
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(2) Deficiency 2 - Review of the applicabie AIR and discus-
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sions with a management representative showed the circum-stances of the related event to have been reviewed by station management.
Item resolved.
197510/
e.
Response Dated August 13,
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(1) Item A.1
- Review of procedures used for Unit 3 feedwater sparger replacement showed improvements to have been incorporated as described in the response.
Item resolved.
(2) Item A.4
- Review of maintenance records showed that an approved maintenance procedure had been used for replace-ment of the 3A recirculation pump seal during the 1975 Unit 3 refueling outage.
Item resolved.
(3) Item B.1
- This deficiency involved failure to report three reportable events. Review showed deviation reports and
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reports to the NRC to have been initiated as stated in
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the licensee's response.
Item resolved.
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(4) Item B.2
- Review of the semiannual report for the first half of 1975 showed chemistry data for the second half of 1974 to have been included.
Item resolved.
(5) This response also identified other actions taken by station management to improve the effectiveness of control over NRC licensed activities.
Inspector observations during conduct of the inspection program in recent months have shown these actions to be complete.
11!
f.
Responses Dated September 2 and 26, 1975 (1)
Item A.1
- Review of the shift supervisor's checklist file showed the current issue of recent procedure and checklist revisions to be on file. Completed checklists for several
'
startups have been reviewed since mid-1975, including those for the Unit 3 startup performed on May 14, 1976, with no dis-crepancies noted.
Item resolved.
,
10/ IE Inspection Rpts No. 050-010/75-11, No. 050-237/75-16 and No. 050-249/75-13 11/ IE Inspection Rpts No. 050-010/75-13, No. 050-237/75-19 and No. 050-249/75-15
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(2)
Item B.2.b
- A licensee representative described new methods being used to effect review of revised quality procedures, whereby a member of the Training Department reviews each revision to establish which positions on the (l station staff are affected by the change.
Info rmation con-cerning the revised QP is then provided to the individuals
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affected. Training Department records showed briefings on revised quality procedures to have been conducted within the allotted time period.
Item resolved.
g.
Response Dated October 16, 1975 Deficiency - Review showed main _tenance procedure 36-512 to have been revised to require notification of the shift engineer when "as found" relief valve setpoints are outside established limits. Item resolved.
h.
Response Dated December 23, 197513/
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(1)
A.1
- This nonen aliance item involved four incomplete or discrepant surveillance test results which were not identified during supervisory review.
Examination of the licensee's corrective actions showed satisfactory test results to have been subsequently observed and documented. Additional guidance concerning supervisory review of surveillance results was also provided as described in the licensee's response.
Item
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resol,ved.
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(2)
A.2 - Review of test records showed that the related tests were completed as described in the licensee's response. A memorandum (
dated January 13, 1976, from the Instrument Engineer also reminded supervisory personnel that incomplete tests should either be rescheduled or completed by issuing a temporary change. During review of the particular tests involved it was also noted that the relays which do not operate with the mode switch in the shutdown mode must function in order to permit reactor startup, thereby assuring their operability prior to resump-tion of plant operation.
Item resolved.
(3)
ltem A.4
- Review of Discrepancy Record No. 75-92 showed hold tags to have been attached to the rejected accumulators until they were destroyed.
Item resolved.
(4)
Item B.1
- A licensee representative stated that the fuel cask handling procedure was in the process of being revised.
This item will be reviewed further during a future inspection.
12/ IE Inspection Rpt No. 050-249/75-19.
])If IE Inspection Rpts No. 050-010/i5-17, No. 050-237/75-23, and No.
050-249/75-20.
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.(5)
Item B.2_ - Licensee representatives stated that the com-
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pleted hydrostatic test procedure still had not been found,
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although examination of records. related to the. Unit 3 k3 recirculation loop bypass piping replacement showed doc-umentation-of satisfactory hydrostatic testing to have been
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performed as. indicated in the licensee's response.
Examination
of the reactor pressure recorder trace showed indications consistent with hydrostatic test documentation included
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with the maintenance records although an' abrupt increase in reactor = pressure to approximately.1250 psig was observed
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during the hydrostatic test due to inadvertent-isolation of.
i the pressure indicator being used for pressure control.
This had been previously. communicated to the inspector and was j
documented in an internal deviation tiport.
This non-compliance. item is resolved, although the matter of pressure control during hydrostatic tests was discussed further:
- during the management interview.
(6)
Item B.3 - Examination of the related surveillance pro-cedure'showed that it'had been revised to delete the
requirement for. calibration of the Unit 1 level sensors at-cardinal points. Item recolved.
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1.
' Responses Dated January 19 and Februarv 6,19761b!
l (1) Item A.1
- The inspector examined a pending request to
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have the vendor placed on the approved bidders list and
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reviewed improved procedures and Quality Procedure 4-5 with
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licensee representatives.
Item resolved.
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I (2) ' Item A.2 -- Quality documentation required by the deficiency j.
was received on April 8, 1976.
Item resolved.
(3) Item A.5
- Review and discussion of this item with the
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responsible operating engineer confirmed the statements in the. licensee's response.
Item resolved.
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(4) Item B.1-Examination of. Modification Package M12-2-74-139 J'
showed red two-part tags for the temperature switches to
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I have been included. Examination of two recent modification packages showed the final documentation checklist to be
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in'use as described-in the response.
Item resolved.
(5)
Item'B.2 - 'The Unit 2 startup test report was submitted
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on December 5, 1975.
Item resolved.
(6) ~ Item B.3
. Discussion of this item _with licensee repre-
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sentives_ demonstrated an understanding of the position expressed in the IE:III letter of March 3,-1976.
Item
resolved.
. 14/ IE Inspe'ction Rpts No. 050-101/75-20, No. 050-237/75-26 and No. 050.
249/75-23.
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Response Dated March 26, 197615/
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(1)
Item A - Review showed that a Minimum Startup Checklist,
DGP l-S2, had been issued as described in the licensee's response.
Completed checklists and procedures related to
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an April 1976 startup of Unit 1 were reviewed without comment.
Item resolved.
(2)
Item B.1
- Representatives stated that the completed
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surveillance tests still had not been found. A memorandum
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documenting completion of the tests was observed to have been placed in the surveillance file as stated in the licensee's response.
Item resolved.
(3)
Item B.2
- Examination ci the procedures referenced in the licensee's response showed revisions to have been made as indicated.
Item resolved.
11.
IE Bulletin Followup This inspection included review of the licensee's action in response to the following IE Bulletins:
74-09, Deficiencies in General Electric Switchgear - Work a.
Request No. 8209 showed Type M26 switchgear installed in "anit 1 to have been inspected as committed in the licensee's response.16/
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Ali auxiliary contact assembly bolts were found to be tight,
_
though some had less than the recommended torque.
sll were tightened to 23-27 inch-pounds per General Elect *:ic recommendations.
Station modification packages M12-2-75-7 and M12-3-75-1 showed I
Type MC 4.76 switchgear roller trip bars installed in Units 2 and 3 switchgear to have been corrected as required.
Item resolved.
b.
74-13, Vulkene "600" Cable - Work Requests No. 3258, No. 1118 and No. 1189 showed motor control centers to have been inspected for the presence of Vulkene "600" cable.
None was found to be installed.
Item resolved.
c.
74-14, Procedures for Steam Qtscharges to the Suppression Pool -
A previous inspection reportli' identified certain commitments made in the licensee's response to this IE Bulletin which had not yet been incorporated into station procedures.
Review during the current inspection showed that Procedure DOA 250-1 had subsequently been issued to define actions in the event of a stuck open relief or safety valve. This procedure was noted to call for the actions indicated in the IE Bulletin.
Item resolved.
15/ IE Inspection Rpt No. 050-010/76-02.
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16/ Ltr, J. S. Abel to J. G. Keppler, dtd 9/9/74.
17/ IE Inspection Rpts No. 050-237/76-01 and No. 050-249/76-01.
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d.
75-03, ASCO Solenoid Valves Work Requests No. 5176 and
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i No. 4930 showed the four valves installed in Units 2 and 3, l
respectively, to have been checked as required. The documents showed the lever-stem clearance for all valves to have been (
left between 0.008 and 0.016 inches. No similar solenoid valves were installed in Unit 1.
Item resolved.
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e.
76-01, Isolation Condenser Tube Failure - This IE Bulletin involved licensee review of instrumentation and procedures which provide for detection of isolation condenser tube leakage
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and subsequent termination of condenser operation. The fol-
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licensee's response-ped from the inspector's review of the lowingcommentsresyf j
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to the IE Bulletin, related procedures, and discussions with licensee representatives:
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(1) Unit 2/3 Procedure DOA 1300-1 requires that the isolation condenser system be isolated in the event of a
tube leak, although specific action points requiring
isolation or notification of management were not ident-ified. The only Unit 1 procedure related to emergency condenser tube leakage was DOA 1300-2, High Level in
Emergency Condenser, and this procedure did not specifically
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require isolating the condenser or the leaking tube bundle.
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(2) The licenset-had not previously made a practice of period-
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ically sampl3ng isolation / emergency condenser shell side water for. activity. The licensee's response stated that daily
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operating surveillance logs require condenser shell side
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water level and temperature to be recorded. Examination t
showed that these surveillance logs actually require only that.the level'and temperature be verified within certain
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limits, although actual recording of-an indicator reading-i was stated to be the standard practice.
i-i (3) The licensee's response to the IE Bulletin stated that a-radiation monitor in the shell side vent provided additional monitoring of condenser tube integrity. Records of a Unit 3 isolation condenser initiation test performed on September'19, i
i 1975, showed that monitor readings of 2.0 and 2.5 were
!
indicated while the condenser was in operation. Annunciation is provided at a scale reading of 20.
Discussions with-licensee representatives. focused on (1) whether an alarm
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would be expected to occur in the event of a-tube leak with good fuel integrity (relatively low coolant activity),
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(2) whether a tube leak would be apparent shortly af ter
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i 18/ Ltr, Bolger to Keppler, dtd 3/17/76.
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i initiation when the vent monitor is affected by a high
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background radiation, and (3) where a meaningful action
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limit could be' established above expected indicator read-
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ings during normal operation (as a result of background i
radiation), but below the levels expected in the event
_
of a tube leak.
These. matters were discussed further during the management inter-view at the conclusion of the inspection.
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12.
Misec11aneous' Items I
a.
Recirculation Pump Speed Mismatch - Supplement A to Dresden Station Special Report No. 22 was noted during earlier Commis-sion review to have raised questions concerning the possibility of jet pump vibration in the event of significant speed differ-
!
entials between the two recirculation pumps. Review of Pro -
cedures DOP 202-1 and DOP 202-2 for Dresden 2 and 3 showed that appropriate limitations on speed differential had been established.
In particular, allowed speed differential as a function of pump speed is specified,'and a limitation on speed of an operating
,
j pump when starting an idle pump is provided.
Item resolved.
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.b.
Replacepgnt of Barton DP Switches - A previous inspection dL'
report discussedplansbythelicenseetoreplacedgffcient
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Barton DP switches.
In June 1975 the licensee advised-- the
)
NRC that the committant date of June 1975 for replacement of
,
switches could not be met because of equipment delivery dates, but
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that all switches would be replaced as soon as practical af ter
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receipt of materials. Review during the current inspection showed that all switches had been replaced except Unit 2 jet - pump riser DP switches and Unit 2/3 off-gas-presssure switches. The
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licensee representatives stated'that replacement of these' switches
was awaiting receipt of materials. This was discussd further
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.during the Management Interview.
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c.
Compeneation for, Inverted Control Rod Boron Tubes - Previous
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communicationsii' between the licensee and the Directorate of
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Licensing discussed the effect of control rod boron tubes deter-mined by the ' licensee to have been inverted during fabrication of the control rods. These communications identified possible decrease l
in the worth of ti.e centrol rods because of settling of boron carbide powder in'the inverted tubes. Review of the liccusee's procedure DTS 8134 showed that the possible reactivity change due
,
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to boron settling is included in the value of "R" (a term which
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accounts for possible reactivity increase during a fuel cycle)
used in the shutdown margin demonstration following ca:h refuel-
ing outage.
Item resolved.
- 19/ IE Inspection Rpts No. 050-237/75-22 and No. 050-249/75-19.
20/ Ltr, Stephenson to Rusche, dtd 6/16/75.
21/ Ltrs,. CECO to DL, dtd 7/2/74; and DL to CECO, dtd 9/30/74.
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d.
Receipt Inspection Procedures - A previous inspection report- /
identfied the need for revision to onsite receipt inspection procedures to provide quality control tracking of materials
received by persons other than the storekeeper. Review of this matter showed that licensee procedures DWP-1 and QP 10-54 now
-
require QC receipt inspection of all safety-related materials received at the station.
Item resolved.
c.
Administrative Procedures - A previous inspection report- /
identified the need to revise Administrative Procedures to: (1)
'
eliminate outdated sections referring to NRB and SRB committees and (2) provide a coordinating or cross-referencing mechanism between procedures.
Review of Administrative Procedures during the current and previous inspections disclosed no remaining ref-erences to defunct groups such as the SRB.
The revised Adminis-trative Procedures also include an alphabetical index and an index showing cross-referencing of the various procedures.
Item resolved.
f.
Control Room Evacuation Procedures - A recent survey by the Division of Operating Reactors resulted in a commitment obtained from Commonwealth Edison by telephone that procedures would be issued to provide for placing the reactor in a safe condition (scramming and initiating decay heat removal) in the event of control room unavailability. This inspection included review
,
cf Procedures DOA 010-4 and DOA 010-6 for Units l and 2/3, respectively, which define immediate and followup operator
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actions in the event of control room evacuation.
Item resolved.
g.
Diesel-Generator Annunicator Procedure (Unit 1) - A previous inspection report:1' noted that a Unit 1 diesel generator annunciator procedure (DOA 9P13 C-6) required revision to includa reference to low temperature conditions.
Review during the current inspection showed that the revision had been issued.
Item' resolved.
h.
Training on Contral, Rod Movements - An IE:III letter which for-warded the report d'
of a previous inspection identified a commitment by the licensee to provide increased training for licensed personnel in the considerations involved in performing control rod movements.
Revieu of the licensee's training records during this inspection showed that this commitment had been ful-filled by the presentation to licensed personnel of an 8-hour training session by a qualified nuclear engineer.
Item resolved.
22/ IE Inspection Rpts No. 050-010/74-OS, No. 050-237/ 74-05, and No.
050-249/74-08.
23/ Ibid.
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24/ IE Inspection Rpt No. 050-010/76-06.
ij/!EInspectionRptsNo. 050-237/75-07 and No. 050-249/75-07.
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Feedwater Piping Stress Analysis (Unit 3) - The 5
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interview portion of a previous inspection report-7""E * "U
confirmed an understanding reached during a July 10, 1974, meeting that a stress analysis of the Dresden 3 feedwater piping would be
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performed. This stress unalysis, designated by Sargent and Lundy as Drtsden 3 Project No. 4989, was described in a report
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dated October 21, 1974. This report stated that overstressing had occurred in only one portion of the system, and that non-destructive testing of high stress areas in that case had indi-cated no material defects.
Item resolved.
,
j.
LPRM Indicators - A previous inspection report- / noted that
most of the LPRM indicators on the control panel 4 x 4 array of Units 2 and 3 were not functioning, such that the operator had little indication of core response during control rod movements.
Observation during the current inspection showed LPRM indicators on Units 2 and 3 to be indicating properly. A licensee represent-ative stated that a modification had been made to the indicators to reduce the voltage to the indicator lamp.
Lamp burnout and required mirror recalibration following lamp replacement had previously been the principal cause of inoperable indicators.
The licensee representative stated that the modification had resulted in good indicator performance since installation.
Item resolved.
28/
k.
Review of Operating Logs - A pre >rious inspection report--
discussed review of operating logs by Operati~, Engineers and Unit Lead Engineers, and noted that the licensee had indicated
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plans to incorporate requirements for such reviews into station p rocedures. Procedures DAP 7-5 and DTS 8235 were observed i
to have been revised to include requirements for log review by the Operating Engineer and Unit Lead Engineer, respectively.
Item resolved.
E!
1.
Long-Standing Jumpers - A previous inspection report discussed plans by the licensee to review jumpers installed in 1972 on the refueling platform rod block interlock to determine whether these jumpers should be climinated by a design change. Review of the jumper log showed that the service platform jumpers had been rcraoved from the jumper log.
This item is resolved, although other comments related to long-standing jumpers resulted from the revieu. (Paragraph 10.d.(1), Report Details).
i 26/ RO Inspection Rpt No. 050-249/74-07.
27/ IE Inspection Rpts No. 050-237/75-19 and No. 050-249/75-15.
28/ IE Inspection Rpts No. 050-010/75-16, No. 050-237/75-22 and No. 050-249/75-19.
29/ IE Inspection Rpts No. 050-013/75-11, No. 050-237/75-16 a$d No.
050-249/75-13.
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