IR 05000315/1987028
| ML17326B322 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 01/15/1988 |
| From: | Azab B, Phillips M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17326B320 | List: |
| References | |
| 50-315-87-28, 50-316-87-28, NUDOCS 8801260166 | |
| Download: ML17326B322 (15) | |
Text
U ~ S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-315/87028(DRS);
50-316/87028(DRS)
Docket Nos.
50-315; 50-316 Licensee:
Indiana Michigan Power Company 1 Riverside Plaza Columbus, OH 43216 Licenses No.
D. C.
Cook Nuclear Plant, Units 1 and
Inspection At:
D.C.
Cook Site, Bridgman, Michigan Inspection Conducted:
September 21 through December 23, 1987 Inspector:
Beth
.
Az gpg if~y I~ /Pg Date Approved By:
Monte P. Phillips, Chief Operational Programs Section de<uui
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Date Ins ection Summar Ins ection on Se tember 21 throu h December
1987 Re orts No. 50-315/87028(DRS);
No.
50-316 87028(DRS)
on previous inspection findings (92701), control rod testing (72700),
shutdown margin/estimated critical condition calculation (61707), control rod worth measurements (61710),
core power distribution limits (61702),
core thermal power evaluation (61706),
and isothermal and moderator temperature coefficient determinations (61708).
Results:
Of the six areas inspected, no violations or deviations were identified in four areas, and two violations were identified in the remaining two areas.
One violation is for failure to perform a Technical Specification surveillance, which is identified as an example to a previous violation (Paragraph 2d).
The second violation is for failure to properly implement a
procedure (Paragraph 5).
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DETAILS 1.
Persons Contacted Indiana Michi an Power Com an W.
G. Smith, Plant Manager M.
Ackerman, Nuclear Fuels Management
"R. Allen, Instrumentation and Control G. Arent, Production Administrative Compliance Coordinator
"K.
R. Baker, Operations Superintendent
~A. Barker, equality Assurance T.
P.
Bei lman, Instrumentation and Control/Planning Superintendent
~A. Blind, Assistant Plant Manager
"L. S.
Gibson, Assistant Plant Manager
~R.
N.
Hennen, Nuclear Supervisor, Technical Engineering
~G. John, Nuclear Fuel Management
~~B.
P.
Lazau, Nuclear Safety and Licensing
~+T.
K. Postelwait, Superintendent, Technical Engineering
"J.
E.
Rutkowski, Assistant Plant Manager AS.
Sharma, Acting Manager, Safety and Licensing
- B. A. Svenson, Licensing Activity Coordinator
"M.
M. Terry, Administrative Compliance Coordinator, Technical Engineering
~V. Vanderberg, Nuclear Fuel Management AM. Whitley, Nuclear Engineering U.S.
NRC
"G.
C. Wright, Chief, Operations Branch
"B. Jorgenson, Senior Resident Inspector
"B.
L. Burgess, Chief, Projects Section 2A
"J. Heller, Resident Inspector The inspector also interviewed other licensee personnel during the course of the inspection including members of the technical, operations, and corporate staff.
"Denotes persons attending the exit meeting on October 22, 1987.
~Denotes persons attending the exit meeting on December 23, 1987.
2.
Licensee Action on Previous Ins ection Findin s (92701)
a.
Closed Licensee Event Re ort 315/84007-LL and 0 en Item 315/84014-01):
These two items were opened to follow implementation of corrective actions to prevent recurrence of DETECTOR Code errors.
The DETECTOR Code analyzed raw flux map data
to determine compliance with power distribution Technical Specifications.
The licensee proposed five corrective actions, three were completed in 1984.
The remaining two items have been completed:
(1)
A standardized input model generator program, STDMODEL, was developed to provide a
common benchmark for all future versions of DETECTOR.
STDMODEL was completed by October 31, 1985.
(2)
A post-processing code was developed to more closely and efficiently monitor DETECTOR performance by printing a summary page of the results.
This modification was completed by December 31, 1985.
The licensee performed an additional corrective action which they were not committed to perform.
After a change is made to DETECTOR, the flux map is processed with three different codes (INCORE and both the old and new version of DETECTOR) and compared to ensure the change in DETECTOR did not introduce any errors into the code.
This corrective action was implemented by December 31, 1985.
The inspector has no further concerns in this area.
Closed)
Part 21 Item (315/85002-PP.
316/85002-PP:
Exxon Nuclear Company reported a computer coding error to the Office of Nuclear Reactor Regulation in a telephone call on March 15, 1985 and in a subsequent letter dated March 22, 1985, as required by 10 CFR 21.21
~
The error was in the TOODEE2 code which affected the LOCA/ECCS analysis for D.C.
Cook Unit 1 as well as some other PWRs.
The error in the code was corrected and analysis reperformed to yield an increase in the peak clad temperature (PCT) to 1827 F, which still satisfied the requirements of 10 CFR 50.46 (PCT shall not exceed 2200 F).
Subsequent errors in the TOODEE2 code were discovered and reported by Exxon to NRR.
NRR required the licensee to perform a
revised LOCA analysis which was submitted by letter dated January 29, 1987.
NRR reviewed and accepted the LOCA analysis, completing their review of this matter in a letter dated June 12, 1987 with an attached Safety Evaluation Report.
The inspector has no further concerns in this area.
Closed 0 en Items 315/85034-04 316/85034-04):
Due to poor procedural controls over the method of quadrant Power Tilt Ratio (gPTR) calculation, gPTR calculations were performed using old 120X power current data for several days after the new 120X currents were determined.
Procedures, 1 and 2 -
OHP 4030. STP. 032, "quadrant Power Tilt Ratio Calculation," were revised to delete any reference to using old 120X currents to eliminate confusion.
The Instrumentation and Control technician places the new current values on the data card
on the Nuclear Instrumentation (NI) Panel when the calibration is performed.
The operators used the currents from the data card for their gPTR calculation, which were the most recent values.
The inspector noted that all the currents on the data card were changed at the same time to eliminate the possibility of using a mixture of old and new currents in the calculation, while the NIs were being calibrated.
The inspector has no further concerns in this area.
(Closed Licensee Event Re ort (315/85064-LL
On November 23, 1985, the licensee submitted an LER stating that procedural errors permitted the time constants for the positive and negative flux rate trips to be set less conservative than required by Technical Specification Table 2.2-1.
Also due to procedural errors, the time constants had not been required to be verified to be within their allowable value at the proper frequency, which was every eighteen months per Technical Spe'cification Table 4.3-1.
Procedures 1 and 2 THP 6030 IMP.231, "Power Range Nuclear Instrumentation Calibration (N41, N42, N43, N44)" allowed the positive and negative flux rate time constants to be set at two seconds
+0. 1 second.
Technical Specifications require the time constants to be greater than or equal to 2.0 seconds.
The positive and negative rate trips mitigate the consequences o'f ejected and dropped rod accidents.
In this instance a larger time constant is more conservative because the circuitry is comparing the actual power signal with a delayed power signal received through a lag network.
A greater lag time constant allows the bistable to trip on smaller rates of change in reactor power.
The Nuclear Instrumentation (NI) calibration procedure did not require a specific verification of the time constants; they were procedurally checked only when the input voltage drifted out of its tolerance.
When the errors in the procedures were discovered all of the time constants were verified and six out of sixteen (eight per unit, two per NI channel)
were found to be less than the Technical Specification (TS) requirement.
Three out of four NI channels for Unit 1 and one NI channel for Unit 2 had time constants that were less than 2.0 seconds.
Technical Specification Table 3.3-1 requires three out of the four positive and negative rate trip channels to be operable.
A review of the plant records through 1981 indicated that of the three Unit 1 NI channels found outside Technical Specification requirements, one channel was verified within its specification in November 1985 and another was verified within specifications in September 1984.
The records reviewed failed to indicate that the Unit 2 channel or remaining Unit 1 channel had been within the Technical Specification requirements for time constant subsequent to 198 The licensee has completed the corrective actions for the event.
The NI calibration procedure was revised to meet the TS requirements and was completed on November 26, 1985 for Unit 1 and November 27, 1985 for Unit 2.
An engineering analysis was completed on June 25, 1986 which evaluated the safety significance of the out-of-specification as found values of the time constants.
It concluded that the plant was not placed in an unanalyzed condition.
A number of violations in the area of TS survei llances led to the issuance of a Confirmatory Action Letter (CAL) on August 30, 1985.
The CAL prompted a review by the licensee to ensure they, were meeting the requirements of all TS survei llances.
The event described above was discovered by the licensee's reviews which were prompted by the CAL.
Subsequent to the CAL seven violations from inspections during the period of August 19, 1985 through February 18, 1986 were grouped together and issued as a Severity Level III violation with Civil Penalty on March 26, 1986 (EA 86-23).
All of the violations dealt with the failure of plant procedures to implement TS and quality assurance requirements.
Three of the violations specifically involved channel calibrations and functional tests that did not adequately ensure that instrumentation channels were operable, or were not performed at the required frequency.
Based on this history, the above event is considered as another example of the previously issued Severity Level III violation in Enforcement Action 86-23 and no further action is deemed necessary.
The inspector has no further concerns in this area.
Closed 0 en Items (315/86006-01 316/86006-01):
The licensee committed to revise procedure
THP 6040.PER.350,
"Isothermal Temperature Coefficient Measurement and Moderator Temperature Coefficient Calculation" to ensure that if irregular slopes occur an evaluation to determine the cause of the irregularity will be performed.
Appendix A was added to the procedure which listed actions to complete in determining possible causes of a nonlinear Isothermal Temperature Coefficient (ITC) slope.
However, the Appendix also stated that if the cause of the abnormal curve could not be determined a "best fit" line should be drawn through the trace.
ANSI 19.6, 1 1985,
"Reload Startup Physics Tests for Pressurized Mater Reactors,"
says that nonlinear data in ITC slopes should be ignored.
Appendix A was revised to state that nonlinear data should not be included in the ITC calculation and if irregularities occur additional data will be taken to ensure consistency.
The inspector has no further concerns in this are f.
Closed)
0 en Items (315/86006-02).
316/86006-02:
An N/A statement that appeared in several Nuclear Group procedures could have been misinterpreted as giving unlimited authority to Test Engineers as opposed to controlling the use of "N/A" through procedural allowances.
The statement was:
"Only those sections deemed appropriate by the test engineer need be completed for each specific test."
The licensee reviewed all Nuclear Group procedures to determine whether the N/A statements should be changed.
The above statement and the phrase:
"at the discretion of the Test Engineer" were removed from the N/A statements.
In some cases N/A statements were expanded, giving more direction on how'to determine what to N/A.
The inspector has no further concerns in this area.
g.
Closed)
0 en Item (316/86020-01):
A number of questions regarding Spent Fuel Pit (SFP)
and Reactor Cavity water level determination were raised during a refueling inspection and have subsequently been answered by the licensee:
(1)
The SFP water level can be read in feet from a stainless steel ruler bolted to the SFP wall.
The accuracy of the ruler was not known at the time of the refueling inspection. 'he licensee checked the accuracy of the SFP ruler and determined it to be 1 4" low (23'ndicated was actually 22'0 3/4" above the top of the fuel).
The licensee raised the SFP ruler 1
~~ " per Job Order No.
009332, completed January 14, 1987, so that the level indicated is now a correct reading.
(2)
At the time of the previous inspection, it was thought that the SFP high level alarm actuated at a level corresponding to 24'
~4" on the SFP ruler.
The inspector observed the level to be 24'" and questioned the licensee as to why the high level alarm was not actuated.
Job Order No.
48155 was written to have the alarm checked and calibrated if necessary.
The actual high level alarm setpoint corresponds to a SFP ruler reading of 24'0
~4" instead of the 24'
4" that was previously thought.
The calibration of the SFP high level alarm was confirmed to be correct and the alarm should not have been actuated at the time of the inspection.
(3)
A water level indicator was installed in the Unit'
reactor cavity, but the accuracy was unknown.
The water level in the Unit 1 reactor cavity was estimated from the rungs of a ladder.
The licensee confirmed the accuracy of the Unit 2 reactor cavity level indicator to be within +
>4" of the actual elevation.
A similar indicator was installed in the Unit 1 reactor cavity per Job Order No.
712239 on June 24, 1987, and verified to be accurate within + <" of actual elevatio (4)
The level surveillance procedure was confusing because it referred to both feet and elevation measurements, therefore the data was recorded inconsistently in both feet above the vessel flange and elevation.
Also, the surveillance was required to be performed during "component movement" which was not defined in the procedure.
The licensee revised procedure, 2-OMP 4030. STP. 037, "Refueling Surveillance," to eliminate the confusion between elevation and feet above the vessel flange by using elevations only.
Also, the term "component movement" has been clearly defined.
The inspector has no further concerns in this area.
Closed 0 en Items 315/87017-02.
316/87017-02:
During an NRC review of a Reactor Operators'equalification Examination, it was discovered that D.C. Cook's Technical Specifications for maintaining Axial Flux Difference (AFD) differed from standard Westinghouse Technical Specifications'tandard Westinghouse TS allow for operation outside of the +5K band around the target AFD for a limited amount of time in a "winged" region.
The Mestinghouse winged region is defined as
+11K absolute AFD at 90K Reactor Thermal Power (RTP) increasing by 1X AFD for each 2X power reduction to a width of +31K AFD at 50K RTP.
D.C. Cook's TS allow the winged function to vary with the target AFD by defining the wings as
+10'eviation from the target AFD at 90K RTP instead of an absolute
+lOX.
Therefore, for target AFDs greater than
+1K at 90K RTP the Westinghouse limits do not bound D.C. Cook's limits.
The methodology for varying the wings with the target AFD was developed by Exxon for Exxon fuel and its analysis is detailed in XN-NF-77-57, "Exxon Nuclear Power Distribution Control for Pressurized Mater Reactors Phase II."
The Westinghouse AFD analysis is detailed in MCAP 8385, 1974,
"Power Distribution Control and Load Following Procedures."
Operating within the winged region ensures limits on peaking factors are not exceeded and initial conditions for the LOCA analysis are valid.
Currently Unit 1 has all Westinghouse fuel and Unit 2 has all Exxon fuel, except for one Westinghouse bundle.
By implementing the Exxon AFD methodology for cores containing Westinghouse fuel, D.C. Cook's TS allowed the potential for operation of Westinghouse fuel outside of the bounds for which it was previously analyzed.
The TS for Unit 1 were revised from stationary wings to varying wings in July 1980, with all Exxon fuel in the core.
Unit 2 TS were revised in March 1982 to maintain consistency between the two units technical specifications; however, Unit 2 had all Westinghouse fuel at the time of the amendment.
Westinghouse personnel stated that they discussed the effects of the varying
wings on Westinghouse fuel in 1982, before the TS change, and concluded that it was not a problem, but did not have documentation of the discussion.
Subsequent to the inspection, on December ll, 1987, personnel from American Electric Power Service Corporation (AEPSC) contacted the inspector and stated that they had additional information, mainly a Safety Review dated August 6, 1981.
The Safety Review addressed Exxon's Power Distribution Control methodology applicability to Westinghouse fuel for Unit 2.
The inspector reviewed the following documentation provided by the licensee:
~
"Safety Review of Unit 2 PDC-II Technical Specifications Prepared by Exxon," dated August 6, 1981.
~
"Safety Evaluation of the Office of Nuclear Reactor Regulation Related to Amendment No.
38 to Facility Operating License No.
DPR-74 Indiana and Michigan Electric Company D.C.
Cook Nuclear Plant Unit No.
2 Docket No. 50-316."
Exerpts from:
XN NF-77-57,
"Exxon Nuclear Power Distribution Control for Pressurized Water Reactors Phase II."
After review of the above documents and discussions with members of the licensee's staff, the inspector concluded that although D.C.
Cook's TS allow operation outside of the Westinghouse generic AFD wings, the Exxon Power Distribution Control methodology still maintains limits on peaking factors for both Exxon and Westinghouse fuels.
The limits are maintained by the use of Exxon's V(z) curve, which is derived for each cycle.
The inspector has no further concerns in this area.
3.
Control Rod Testin (72700 The inspector reviewed the surveillance,
- 1 THP 4030 STP.387,
"Rod Drop Measurements,"
completed September 26, 1987, for compliance with Technical Specification 3/4. 1.3.3, which requires a rod drop time from the fully withdrawn position to the dashpot entry of less than or equal to 2.4 seconds.
The surveillance was performed properly and the results complied with the acceptance criteria and Technical Specifications.
No violations or deviations were identifie.
Shutdown Mar in/Estimated Critical Condition Calculation (61707)
In the area of shutdown margin and estimated critical condition calculations, the inspector reviewed various procedures and their results for technical adequacy, compliance with Technical Specifications, and consistency with design predictions.
The following documents were employed during the review:
~
"Nuclear Parameters and Operations Package, Donald C.
Cook Station Nuclear Plant (Unit 1, Cycle 10)."
"*12 THP 6040PER.357, "Initial Criticality, All Rods Out Boron Concentration and Nuclear Heating Level," completed October 4, 1987.
~
~"1 THP 6040PER.359,
"Zero Power and Power Ascension Tests,"
completed October 11, 1987.
No violations or deviations were identified.
5.
Control Rod Worth Measurements 61710)
The inspector reviewed **1 THP 6040 PER.352
"Rod Worth Verification Utilizing RCC Bank Interchange,"
performed October 6,
1987 for technical adequacy and compliance with Technical Specifications.
The measured rod worths agreed with the predicted rod worths recorded in the Nuclear Design Report and were well within the design acceptance criteria.
During review of *"1 THP 6040 PER.352, the inspector identified a violation (315/87028-02(DRS))
of Technical Specification 6.8. 1.C, which states that written procedures covering surveillance and test activities of safety related equipment shall be established, implemented and maintained.
Contrary to the above, procedure
~~1 THP 6040 PER.352 which covers testing of safety related equipment (control rod worth measurements)
was not implemented properly, in that a step in the procedure was not followed.
Step 8.2.5 of the procedure instructs the user to obtain three boron samples from the reactor coolant system and one sample from the pressurizer and record them on Form No. 352-3, attached to the procedure.
The boron samples are taken before rod worths are measured to ensure the system is well mixed.
The samples were not documented on Form No. 352-3, as required by procedure, but were later found to be recorded in the Nuclear Engineers'ogbook.
The inspector showed the procedural error to the Lead Nuclear Engineer, who responded by adding a revised Form No.
352-3
to the procedure, which included the boron samples that were previously missed.
The inspector also noted during the procedure review that a
signature was missing in Step 11.0 (Supervisory Review).
When brought to the. Lead Nuclear Engineers's attention, he signed and dated the blank on October 15, 1987, although the procedure was completed and signed off by other personnel on October 6, 1987.
While the violation was a failure to properly implement a procedure, it is of equal concern that the procedure reviews performed by licensee personnel failed to identify the above problems.
No additional violations or deviations were identified.
6.
Core Power Distribution Limits 61702)
The inspector reviewed a number of procedures in the area of core power distribution limits for technical adequacy and compliance with Technical Specification limits and surveillance frequency requirements.
The inspector verified that the licensee complied with Technical Specification limits on quadrant power tilt ratio, hot channel factors, axial flux difference, and departure from nucleate boi ling parameters by reviewing the following surveillances:
~
""1 THP 4030 STP.330,
"Surveillance of Core Power Distribution Limits," performed October 7, 1987.
~
1-OHP 4030.STP.030,
"Operations Daily and Shift Survei 1'lance Checks (Modes 1, 2, 3, 4)," performed October 15 through 18, 1987.
~
1-OHP 4030.STP.032,
"quadrant Power Tilt Ratio Calculation,"
performed October 16 through 18, 1987.
No violations or deviations were identified.
7.
Calibration of Nuclear Instrumentation S stems 61705 The inspector reviewed procedure, 12 THP 4030 STP.362,
"Incore-Excore Detector Calibration," performed October 8-10, 1987 for technical adequacy and compliance with Technical Specification 4.3. l.l. 1.
During the review, the inspector noted that Step 7.3 of the procedure was missing a line of instructions.
This apparently resulted from a printing error from the word processor and will be corrected.
No violations or deviations were identified.
8.
Core Thermal Power Evaluation (61706)
The inspector reviewed the following completed procedures concerning core thermal power and verified that the nuclear instrumentation system's power range channels were properly adjusted to equal the calorimetric power when required:
~
- "12 THP 4030 STP. 219,
"Thermal Power Measurement and Reactor Coolant System Flow Rate."
~
1-OHP 4030.STP.029,
"Reactor Thermal Power Determination," performed October 14-18, 1987.
No violations or deviations were identified.
9.
Isothermal and Moderator Tem erature Coefficient Determinations (61708)
The inspector reviewed procedure,
"*12 THP 6040 PER.350,
"Isothermal Temperature Coefficient (ITC) Measurement and Moderator Temperature Coefficient (MTC) Calculation performed October 5, 1987.
The calculated MTC values were well within the required
+3 pcm/~F of the predicted number from the Nuclear Design Report.
No violations or deviations were identified.
10.
Exit Interview The inspector met with the licensee representatives (denoted in Paragraph 1)
on October 22, 1987.
The inspector summarized the scope and findings of the inspection.
The licensee acknowledged the statements made by the inspector with respect to the violation (denoted in Paragraph 5).
The inspector also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspector during the inspection.
The licensee acknowledged statements made by the inspector and stated that the Nuclear Design Report referenced within this report was proprietary, but references to the document would not be considered proprietary.
The inspector reviewed additional information provided by the licensee subsequent to the inspection, and re-exited with the licensee representatives (denoted in Paragraph 1) via telecon on December 23, 1987.
i