ML19256A033
| ML19256A033 | |
| Person / Time | |
|---|---|
| Site: | Crane, Davis Besse  |
| Issue date: | 08/23/1978 |
| From: | Creswell J, Phillip G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML19256A031 | List: |
| References | |
| TASK-TF, TASK-TMR 50-346-78-17, NUDOCS 7809260195 | |
| Download: ML19256A033 (13) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEME!E REGION III
__ Report No.-50-346/78-1,7j, Docket No. 50-346 License No. NPF-3 Licensee: Toledo Edison Company Edison Plaza 300 Madison Avenue Toledo, OH 43652 Facility Name: Davis-Besse Nuclear Power Station, Unit 1 Inspection At: Davis-Besse Site, Oak Harbor, OH Inspection Conducted: April 4-7, May 17-19, 25, June 27-30, July 20-21, and July 27-28, 1978 W
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Inspectors:
J. S.
reswell v,j l
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!Y G. Phillip f}ffdw& S
'/b 78 Approved By:
J. F. Stree':er, Chief Nuclear Support Section 1 Ins'>ection Su= mary Inspection on april 4-7, May 17-19, 25, June 27-30, July 20-21 and 27-28,1978 (Report No. 50-346/78-17)
Areas Inspected:
Routine, unannounced inspection of startup testing and tour of outside areas. The inspection involved 142 inspector-hours onsite by three NRC inspectors.
Results: Of the two areas, one item of noncompliance was identified in one area (Infraction - failure to conduct radiation surveys - Paragraph 7) and an item of noncompliance (Infraction - failure to follow procedures, Paragraphs 2, 5b and 6) were identified in the other area.
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DETAILS _
1.
Persons Contacted
- T. Murray, Station Superintendent G. Novak, Superintendent, Power Engineering
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- C. Domeck, Nuclear Project Engineer F. Faist, B&W, Site Operations Manager
- W. Green, Administrative Coordinator
- J. Buck, QA The inspector also talked with and interviewed other licensee employees, including memebers of the technical and operations staff.
- Denotes those attending the exit interview.
2.
Review and Approval of Startup Test Results The inspectors reviewed the licensee's efforts related to review and approval of startup test results. Procedures AD 1801, AD 1801.01 and applicable PEI delineate startup test results review requirements for the plant staff, Station Review Board, Company Nuclear Review Board, and NSSS supplier (Babcock and kilcox).
The inspectors determined that:
Results of power level plateau tests of a continuing nature (e.g.,
reactivity coef ficients at power) were being reviewed by the plant staff and NSSS supplier before power escalation but not by the TECo corporate technical staff.
The corporate technical staff intended to conduct its review af ter the continuing tests were completed at 100% power.
TECo corporate tedanical staff reviews of results of certain com-pleted tests were not expeditious (e.g., results of test 800.29
" Dropped Rod Test", were reviewed approximately three months af ter test completion and results of test 800.15 " Unit Power Shutdown",
were reviewed approximately two months af ter test completion.)
The only inspector finding in this area that represented an item of noncompliance was the failure of the Company Nuclear Review Board to conduct any independent reviews as required by procedure AD 1801, Section 2.2.11, which implements an independent review commitment made in FSAR Section 14.1.1.j.
This is considered to be an item of noncompliance of the infraction level in that procedure AD 1801 was s;
The not implemented as required by Technical Specification 6.8.1.a.
licensee indicated that prompt attention would be taken to implement the procedure and FSAR carniement.
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With regard to TECo corporate review of results of tests of a continu-ing nature, the licensee stated that Power Engineering would begin re-viewing the results at each plateau prior to concurring with escalation to the next plateau.
The Plant Superintendent stated that power escala-tion would not be commenced until Power Engineering concurrence was ob tained. This method of review will fulfill the commitment made in e
FSAR section 14.1.8.2 to conduct an analysis of the significant para-meters at each major plateau prior to initiating an additional power escalation including results of unit heat balance test, reactivity coef ficient measurement, core power distribution measurement, unit load steady state test and, unit load transient test.
With regard to untimely completion of TECo corporate reviews of startup test results, the licensee stated that future TECo corporate reviews would be prompt and the Test Program Manager would be reminded of his responsibility to assure expeditious reviews of test results by all in-volved parties.
The licensee also stated that, prior to giving concurrence with escala-ting power to the next plateau, Power Engineering would review any in-complete testing. This review will be conducted to assure that the safety of the plant is never dependent upon the performance of an un-tested system as required by procedure AD 1801, Section 1.6.
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3.
Organization and Staffing of Power Engineering and Construction Group The inspectors reviewed the organization and staffing of the Power Engineering and Construction group to determine if those areas satis-fied the descriptions delineated in FSAR Section 13.1.1.2.4.
The in-spectors review included discussions with the Vice President, Facilities Development, General Superintendent, Power Engineering and Construction, and other group personnel and a review of resumes of all group personnel.
The inspectors determined that the group organization and staffing were consistent with the FSAR descriptions.
The inspectors reviewed the group workload and determined that a great deal of time was being devoted to resolution of Davis-Besse Unit 1 problem areas and to obtaining Construction Permits for Davis-Besse Units 2 and 3.
These efforts appear to be a contributing factor in delays experienced in reviews for Davis-Besse Unit 1 facility change requests and approval of Unit 1 startup test results. From a review of the FSAR for Units 2 and 3 it appears the licensee does not plan a significant increase in the staffing level of the Power Engineering and Construction Group to compensate f or the increased workload which will develop following the issuance of Construction Permits for Units 2 and 3.
The Vice President, Facilities Development, stated that re-cruitment efforts were presently underway to increase "the engineering staff.
The Vice President stated that he was familiear with the docu-ment WASH-1130, " Utility Staf fing and Training f or Nuclear Power."
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.s The Vice President also stated Davis-Besse Unit I would receive priori-ty attention over Units 2 and 3 from the Power Engineering and Construc-tion Group whenever priority attention is necessary to avoid compromising the safety of operation at Unit 1.
The inspectors had no further questions concerning this matter at this time.
4.
Review of 13.8 KV Bus Transfer Testing During review of the results of acceptance test TP 400.04, "13.8 KV System Acceptance Test", the inspectors reviewed a memorandum dated October 14, 1976, from a Test Leader to the Test Program Manager. The writer of the memorandum indicated that breaker throwavers between auxiliary and startup transformer supplies to 13.8 KV busses A and B were not being properly tested.
The inspectors concluded from further review of documentation and discussions with involved personnel that the licensee had not performed an adequate evaluation of the concerns ex-pressed in the memorandum to verify that all features affecting the availability of the of fsite power sources were tested to demonstrate the features would operate in accordance with design. However, the
' inspectors' review did not reveal any deviations from licensee commit-ments or items of noncompliance.
The inspectors requested and reviewed the results of tests involving
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breaker throwavers (manual and automatic) between supplies to 13.8 KV busses A and B.
From this review the inspectors determined the follow-ing testing had been documented in test procedures as of Ju.ly 1978:
Feature Tested Procedure No.
Date of Testing Manual throwaver (some but not TP 0400.10 October 1976 all) from local switchgear Automatic throwaver from auxiliary PT 5103.01 December 1977 transformer "to startup trans-formers 01 and 02 Automatic throwavers between ST 5080.02 November 1976 startup transformers 01 and 02 Documentation was not available to indicate the following testing had been completed; however, the licensee stated that the testing had been satisfactorily accomplished:
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Completion of marmal throwovers Being Approved Prior to exceeding from local switchgear 15: power plateau upon return to power Manual throwovers from control Being Approved Prior to exceeding 15% power plateau
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room upon return to power 1917 252
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s Subsequent to the inspection, the licensee infor: d the inspectors by telephone that the above testing had been satisfactorily completed as coesitted.
The inspectors stated that the testing of the manual breaker throwaver tests and the automatic throwover testing contained in Pr 5103.01 should have-been completed in a more timely fashion.
In order to determine if there were other untested electrical design features, the inspectors reviewed the results of all electrical tests described in Seciton 14 of the FSAR.
The inspectors did not identify any other inadequate testing or unresolved concerns of test personnel.
Review of TP 401.01, 345 KV Switchyard 125V D.C. System Pre-operational Tests, revealed that Power Engineering received the test results dur-ing November, 1976. As of date of the inspection, the results had not been reviewed. Administrative procedures requiring the review of the test results were not effective during November,1976.
Since the test-ing of this equipment involves the of fsite power sources the test re-sults are considered to be of significance. The licensee has assented to review the test results.
5.
Inspection at Corporate Offices and Continuing Review of November 29,_
-1977 Event, a.
Corporate Office Inspection
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.During.the inspection, Power ' Engineering's analysis of the _ November; (29, 1977 event which involved loss 'of; f orced reactor coolant flowj was reviewed.
During the review the inspector examined several memoranda between the licensee, NSSS supplier and trchitect engineer (AE) regarding the operation of the electrical system during the event. The AE informed the licensee of the following:
The original intent of the 30-second delay *,was two-fold both of which were predicated on a unit trip occurring for non-electric al reasons, i.e., either a reactor or turbine trip.
There was to be no delay if the trip was from a cause within the electrical system, i.e., either main generator, unit auxi-liary or main transformer. First, the delay provides assurance of continued full reactor coolant flow without the risk of an unsuccessful transfer of station auxiliaries. Second, it reduces and may entirely eliminate the possibility of turbine-generator overspeed.
In addition to the above 30-second time delay benefits recognized
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by the AE, the NSSS supplier indicated the additional benefit of electrical b' raking of reactor coolant pu=ps during a LOCA occurring at the discharge of a reactor coolant pump.
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- Time between turbine trip and opening of generator output breakers.
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As a result of a licensee request, the AE contacted the NSSS supplier to determine the impact on the reactor system of totally eliminating or selectively eliminating the 30-second delay.
The NSSS supplier made the following statements in response to licen-see concerns:
In the.unlikely event of a LOCA, there have been predictions that the hydraulic turbining of the pump may reach over. peed beyond
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practical design limitations that may result in failure of the pump, motor or flywheel. Due to;two phase flow, the resulting overspeed is indefinite and cannot be accurately predicted. Per BAW-100400, the overspeed has been calculated with some conser-vative assumptions. Without the electrier.1 braking resulting from the 30 second delay the typical worst case maximum overspeed is 3311 rpm ot 276% of the rated 1200 pm.
With electrical braking a typical maximum of 1700 rps or 142% results.
The Topical Report also conservatively evaluates the high stress areas of the RCP motor flywheel by fracture mechanics analysis, and this indicates that same form of protection is required to preclude overspeed. The safety factors at 140% of rated speed seem more than adequate to preclude failure. Conversely, it does not show conservatively that the safety factors are adequate to preclude failure if there is no electrical braking.
It is our understanding that the generator trip mechanism is not safety grade and thus credit was not claimed in the FSAR. However, Topical BAW-10400 implies that electrical braking should be imple-mented. The generator would provide braking for the RCP motors whether or not it is tripped if the auxiliary breaker is not opened.
B&W considers the 30 second time delay to be prudent, even though it may not be considered in the safety analysis. However, it should compromise plant operation during the more common transient not events.
If necessary to reduce the delay, we recommend a reduc-tion to 20 seconds in order that the period of the large break LOCA would be covered.
The turbine generator vendor was also contacted with regard to the t= pact on the turbine generator.
The turbine-generator vendor ex-predsed a concern that there is a possibility of : 'arential turbine overspeed if electrical energy is fed back to the,
tor from a reactor circulating pump (s) should the pump (s) act, a hydraulic driven turbine (s) as a result of a break in an outlet line to one of the pumps.
The turbine-generator vendor suggested that the possibility of a LOCA wh'th could contribute to a possible over-speed during the 30 second delay period should be carefully evaluated. '
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A memo from the AE Jispositioned the generator overspeed concern:
We have evaluated this concern relative to Davis-Besse, Unit 1, and have concluded that no problem exists. Our conclusion is based on the fact that only one reactor coolant pu=p can be tur-bf.a at any one time due to a LOCA and that the resulting induc-tion generator action will produce less than 4000 KW.
This figure is significantly less than the 10,500 KW required to motor the turbine gecerator let alone accelerate it.
The inspector had no other co=ments about this matter.
As a result of the licensee's analysis of the November 29,1977 event, two facility change requests involving the electrical system were ini-tiated.
,. Facility Change. Request No.77-525 proposed to not trip the makeup; pumps on. the loss of offsite power.
The reason given for -the change
< was that Lduring auxiliary feed pump operation all the makeup flow that is possible is needed to maintain' Jevel in the pressurizer. This change is presently under review by. the licensee.
Facility Change Request No.78-049 proposed:
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1.
Remove undervoltage stripping of unit srb and bus tie feeders on A&B busses due to unde rvoltage device #47.
2.
Add undervoltage stripping of motor feeders on C2 and D2 busses.
The stripping on undervoltage is to occur af ter time delay.
The reason for change I was a reference to correspondence between the licensee and the AE which stated:
The present arrangement initiates tripping of all load feeder breakers based on appropriate time and voltage settings of device 47.
The original intent was to guarantee having unloaded 13.8 KV busses when manually energizing them through the startup transformers.
Our study showed that when the 13.8 KV busses are to be energized, the motor feeder breakers must be shed prior to re-energization of the busses. However, all other loads (bus-tie transformer and unit oubstations) of the 13.8 KV switchgear may remain connected, and can be re-energized simultaneously without creating severe
's low voltage conditions.
The reason given for change 2 was that it is required for action unless it can be proven that there will be no equipment damage or source trip if the entire bus load is energized all at once. During the inspector's review of the FCR a question arose as to which motor feeder breakers were involved. As a result of this review, it was determined that all portions of the FCR should not be implemented unless an analysis showed that motor feeders on C2 and D2 should be be stripped. Plant. personnel were informed of this requirement.
19171255
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b.
Continuing Review of Nove=ber 29, 1977 Event The inspector reviewed computer logs, operating records, and inter-
.. viewed operating and technical personnel.about( equipment problems
. identified during the November 29, 1977 event..
During the event an Slio was ' involved with an attempt to start the :
station air compressor in order to supply air to valves and the auxiliary boiler.
In his attempt, he experienced difficulty in closing E3 and F3 breakers.
Later analysis by the AE indicated the
- control room switch had to be turned to off prior to reclosing thei
- breakers. As of the date.of'the inspection, the. operating proce-
' dure had not been revised to include the aforementioned requirement.
The licensee ~did initiate a temporary procedure modification dur-ing the inspection to include the requirement.
During the inspector's review of the computer printout associated with the event and discussions with Power Engineering personnel,
, numerous erroneous computer alarms vera identified.
The inspector reviewed FCR's and work orders associated with these erroneous alarms. During the review it was noted that some computer alarms were associated with transmitters that also supply input to control room annunciators. The. licensee stated that efforts were underwayj to assure control room annunciators are indicating properly.
s During the. review of equipment problems, it was noted that there was dificulty with starting reactor coolant pumps (RCP) because of a
.45 gpm component cooling water flow interlock.
In order to start
, a RCP, component cooling water flow to the pump seal and motor heat exchangers must be greater than 45 gpm. Review of the component cooling water preoperational test results indicated that, although flows to heat exchangers were greater than 45 gpm, they were marginal.
The marginal flows appear to be related to piping design.
In the process of starting a RCP it is sometimes necessary for an operator to observe flow instrumentation inside containment and then coc= uni-cate the greater than 45 gpm flow condition to the control room opera-tor who then starts the RCP.
The licensee has been asked to evaluate the method of starting a RCP under these conditions in light of meet-ing Technical Specification requirements to provide flow for the mixing of reactor coolant during boration changes.
During the review of online computer output generated during the
'3 November event, printouts were noted that indicated service water (SW) and/or camponent cooling water (CCW) ; pump breakers were racked The licensee could not determine from operating or tagging ' logs out.
what CCW or SW pumps.breskers. vere. racked out. The licenset is're-viewing the -need for doc xmenting inoperable safety-related equipment ;
even in situations where action statements are not~ entered.
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Review of Emergency Procedure EP 1202.03 and discussions with opera-ting personnel revealed that step 3.2 of the procedure was not fol-loved in that the No. 11 Auxiliary Transf ormer Breaker to 13.8 KV bus A was not opened prior to transferring unit loads to a startup transformer when an "A" bus transfer was first attempted. Not it-plementing the procedure is considered to be an item of noncompliance at _ the Inf raction level with Technical Specification 6.8.1.a.
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.was noted that if the procedure had been followed offsite power would have been restored earlier in the transient.
During the analysis of the November 29, 1977, event power engineer-ing personnel noted that some data recorded by the reactimeter was not identifiable. Plant personnel have initiated procedure modifi-r cations to assure that when the reactimeter is used to record data all parameters measured are clearly documented..In light of the cause of the November 29, 1977, event, e.g., patch panel shorts, the licensee has issued a standing order to require that patch panel wiring be checked by an I&C engineer prior to use.
6.
Review of Incore System Capability to Determine Worst Case Thermal _
Conditions The inspector reviewed a fuel assembly power ratio map taken at 100%
power. The inspector noted that the center assembly had the same
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value of average assembly power as four assemblies symmetrically located two assembly positions away. This was considered anamolous s
since the center assembly was predicted to be the highest power as-sembly in the core. Further investigation revealed that Incore String One was out of service when the map was taken.
The licensee first noted the failing detector string on Deced er 18, 1977. At that time, the detector at level 5 was a factor of two lower than the first choice replacement. A computer sof tware adjustment was made to force die detector data into a failed condition on December 18, 1977. On January 3,1978, when the 75% core power distribution data was taken the licensee noted that all of the detectors in string I were still operable with the exception of level S.
During the period of January-March 7,1978, incore detector data was taken from the multi-plexer.
On April 1,1978, the licensee was receiving conflicting data on String 1.
At this point the licensee hypothesized that the detector was becoming waterlogged and/or drying out.
To determine whether there was definitely a cabling problem the licensee swapped cabling between the incore tank and multiplexer.
This action did not correct the problem. At this point there was also a concern that the connector for the cabling and detector was faulty..
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- On April 13, the vendor's corporate offices were notified that there was a concern that string 1 was in the maximum radial power fuel ele-ment H8 and its first choice replacement H-10 was underpredicting the radial assembly power. Vendor site personnel recoc= ended that the licensee be advised to program the computer to apply a factor 1.202 to the replacement string data to correct for underpredicting string H-8 power.
This factor was proposed to be entered into the CALNRM array which at that time contained the value 1.0 for all replacement strings. As indicated in paragraph 9 of this report, administrative controls concerning failed detector treatment are under review.
The f actor of 1.202 referenced above was based on the ratio of the pre-calculated steady-state relative radial power distributions for 100%
FP, case 6, 50 FPD for assemblies H-8 and F-8.
The actual exposure value at the time the calculations were perfor=ed on April 5,1978, was approximately 70 FPD.
Since an FN H of 1.697 was calculated versus a Technical Specification limit of 1.717 the inspector asked the licensee to evaluate what the FN A H would be if conservative values of power for the center assembly were used. This analysis will be reviewed in a future inspection.
On January 18, 1978, the licensee performed an incore channel check per surveillance test procedure ST 5033.1. This check indicated incore r-(
string I was out-of-service. On January 20, 1978, the reactor was escala-ted above the 75% power level. By having incore string 1 out of service, the incore detectors were not capable of determining worst case thermal conditions since string I was located in the peak power assembly and conservative adjustments were not made to account for this fact.
Test procedure TP 800.00.0, Section 5.10 states:
For power escalation above 75% of rated power, the capability of the incore detectors and either on-line or off-line systees for determining axial imbalance and worst case thermal conditions (minimum DNBR and maximum linear heat rate) must have been verified.
The requirements for verification in TP 800.00.0, section 5.10 were not satisfied. This is considered an item of noncompliance of the Infraction level with Technical Specification 6.8.1.c.
7.
Tour of Outside Areas During the inspection the inspectors toured the outside areas of the plant.
Observations of the radwaste storage pad area near the borated water storage tank revealed a 50 gallon drum of radwaste with a marking indi-cation a radiation level of 400 mr/Hr at contact to be located spproxi-mately three faet from the radwaste storage pad perimeter fence. The inspectors requested a radiation survey and the survey revealed a radia-tion level of 13 mr/Hr immediately exterior to the fence. A review of
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records and discussions with Health Physics personnel' revealed that a radiation survey had not been perf ormed when radwaste materials had last N
0917 258.
been placed in the storage area and existing materials rearranged on June 27, 1978.
Not performing the radiation survey as required by 10 CFR 20.201(b) is considered an item of noncompliance of the Infrac-tion level.
The inspectors also noted maintenance was being performed in the Pri-mary. Water Storage Tank. Review of Health Physics records revealed that levels of contamination inside the tank were determined to be
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accep table.
8.
Review of Fuel Melt Limit Bases _
During the review of TP 800.00, TP 800.29, e a the Technical Specifi-cations three dif ferent values for the fuel melt limit were noted.
The licensee was asked to identify the corre' c value and the reference doc-ument for its determination.
The licensee provided the inspect'.- with a copy of a B&W report entitled,
" Selective Fuel Loading Report tor Davis-Besse 1" which was transmitted to TECo via a memorandus (BWT-1467) from R. Berchin to C. R. Domeck, dated February 2,1977.
The report provides information concerning the loading of eight assemblies (Class 2) which do not meet the 20.4 Kw/f t central fuel melting limit used in the " Davis-Besse Unit 1 - Fuel Densi-fication Report". BAW-1420. Of those eight asse=blies, two have ratings
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of 20.17 Kw/f t which is the value for the fuel melt itsit used as the
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acceptance criteria during initial startup testing.
The licensee considered the reports L= pact on nuclear safety to be in-significant.
Since the licensee did not perform a safety evaluation of the selective loading an evaluation was requested by the inspecto prior to elevating power above 50% power.
Subsequent discussions with licensee and vendor representatives revealed the following for Cycle 1:
The selectively loaded assemblies have essentially the same nuclear a.
characteristics as the Class 1 assemblies such that acymetric loading of the Class 2 assemblies can be ignored when performing eighth core sycmetric calculations.
b.
By using an acceptance criteria of 20.17 rw/f t for all assemblies during the " dropped rod" test, acceptable test results assured that no fuel melt limits would be exceeded.
's The selective loading analysis was performed for Davis-Besse Unit 1.
c.
Discussions regarding Cycle IB and review of the safety evaluation re-vealed the following: '
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The vendor stated that Cycle IB power distributions have been eval-a.
usted against the criteria set forth in the selective loading re-port. The eight (8) fuel assemblies which were selectively loaded exhibit greater margin in Cycle IB than in the previous design. Thus, the selective loading report conservatively bounds maximum heat rates for Cycle 1B.
b.
The licensee requested that selective loading be used by the vendor for the six (6) applicable assemblies (from batch 3) in Cycles 2 and 3.
The inspector asked whether the selective loading evaluation for Cycle IB was for worst case conditions and included the " dropped rod" cond'i-tion. As a result of this query an analysis for the " worst" power peaking conditions allowable by the Reactor Protection System was per-formed. This evaluation showed the maximum heat rate for the 2 assem-blies with allowable heat rates of 20.17 Kw/f t increasing for Cycle IB and decreasing for the 6 other Class 2 assemblies. Maximum heat rate for the two ltmiting Class 2 assemblies was calculated to be 16.18 Kw/ft.
Discussions with the licensee's Project Engineer indicated that the sel-ective loading report was not submitted to NRC for review because the selectively loaded assemblies had an insignificant i= pact on nuclear
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safety. The inspector informed the licensee that the report should
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have been transmitted to NRC for review under the provisions of 10 CFR 50.55(d).
10 CFR 50.55(d) is a condition of construction permits issued by the NRC and requires an applicant to file information needed to bring the original application for license up-to-date at or about the time of completion of the construction or modification of the facili-ty.
The information contained in the selective loading report was nec-essary to bring the FSAR as supplemented by RAW-1401," Davis-Besse Unit 1 Fuel Densification Report [up-to-date.
However, since 50.55(d) no longer applies to the licensee in that the construction permit has been re-placed by the operating license, a citation will not be issued.
9.
Review of Ouadrant Power Tilting During Rod Drop Testing Inspection report 50-346/78-06 identified core tilts experienced during rod drop testing as questionable. Further information on the subject indicated that the outputs of nuclear instrument channels 5 and 6 were switched on the computer printouts.
In addition an incore string in quadrant YZ was out of service and its first choice replace =ent was very i
near the dropped rod which unduly biased the tilt calculation. Admini-strative controls concerning f ailed detector treatment are currently under review.
The inspector had no further questions concerning this matter at this tLme.,-
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10.
Review of Unit Lead Steady State Test The inpsection of this test revealed there was no entry in the chrono-logical log for data taken at the 30% power level. In addition, TP 800.00 indicates the test' at 30% power was co=pleted on Novecher 14, 1977. Test data indicates the test was performed on December 15, 1977
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which was af ter the date the 40% power data was taken.
It was further noted that Enclosure 7 of the test procedure was removed from the pro-
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cedure. defined the itsits on steam generator outlet pres-Review of data accumulated during the testing indi-sure versus power.
cated some of the values for outlet pressure were outside of the limits.
This matter is considered unresolved and the test results will be re-viewed in a future inspection.
11.
Review of ICS Tuning at Power Testing Inspection of this testing revealed that sections 7.5.1, steam generator level control verification and 7.5.2, turbine header pressure control verification had been rem oved from TP 800.08.
The licensee maintains that this testing has been performed during other tests.
This matter is considered unresolved and will be reviewed in a future inspection.
12.
Station Blackout Procedure
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The inspectors reviewed procedure EP 1202.02, " Station Blackout", revision 5, dated June 19, 1978, and noted that the loading of a makeup pump on an emergency diesel generator following a loss of offsite power could result in emergency diesel generator overload if an engineered safety feature actuation signal was received af ter the blackout. The licensee revised the procedure to direct the operator to secure the makeup pump if an ESFAS occurred during a blackout.
The licensee is investigating the automatic stripping of the makeup pump upon ESFAS initiation.
13.
Review of Company Nuclear Review Board (CNRB) Minutes with Regard to Power Escalation Testing Review of CNRB minutes dated October 27, 1977, revealed that the plant superintendent stated that the station personnel had formed some " bad habits" during the recent startup test program by having to "gerry-rig" systems to complete tests, and that personnel errors can be expected to be reduced but not completely eliminated with time.
The plant superintendent and CNRB chairmen were interviewed to determine c
that the expressions " bad habits" and "gerry-rig" meant and what actions were taken to correct the condition. As far as the term "gerry-rig" was concerned, it was determined that some systems were tested in piecewise segments.
The term " bad habits" referred to test personnel having to incorporate a large number of modifications to testing procedures. No items of noncompliance were identified.
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4 14.
Further Review of Incore System The inspector determined that leakage correction factors programmed in Prior to the computer CALFI array were implemented on April 1,1978.
this time all values in the array were equal to 1.0.
The leakage correction factor is applied directly to the self-powered. nuclear det-ector, (SPND) output signals and as the name suggests corrects for Icak-age.
The factor when applied can result in up to 1.5% change in the e
corrected SPND output.
The inspector questioned the lack of use of background detector correction factors.
It was explained that at Davis-Besse the background was very small (4-5% of SPND output) and that uncertainties in the determination of the background would lead to more uncertainty when the background <cor-rection was applied.
However, the licensee has determined that recent of incore detecto::s may require use of background correction.
replacement In regard to detecting incore '. detector failure and appropriate actions to be taken, the vendor has made the following reco=sendations:
An,y detectors which are identified by an engineering analysis to read more than 20% different than expected at any one time or to consistently read 15% more than expected in a core under nominal steady state conditions should be assumed to have failed and should be locked out manually. Licensee implementation of these reco=-
mendations will be examined in a future inspection. No items of noncompliance were identified.
15.
Continuing Review of Roc Drop Test Evaluation Since certain conservatism were removed during the analysis of the above subj e ct, the inspector asked for further information about the valuesA determined for radial local peak and peak to average segment power.
value of the radial local peaking factor of 1.002 was supplied to the inspector.
Since this factor, which represents peak pin power to average pin power in the " hot" asse=bly, appeared low the inspector requested further information 'about the development of this factor. This matter is considered unresolved.
16.
Unresolved Items Unresolved items are matters about which more Information is required in order to ascertain whether they are acceptable items, items of noncom-pliance or deviations. Unresolved items are identified in paragraphs 10, g-4 11 and 15.
17.
Exit Interview The inspector met with licensee representatives (denoted in paragraph 1) on July 28, 1978 to sne-arize the findings of the i. spection.
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