IR 05000338/1981005
| ML20004C185 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 04/09/1981 |
| From: | Dance H, Tattersall A, Webster E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20004C175 | List: |
| References | |
| 50-338-81-05, 50-338-81-5, 50-339-81-03, 50-339-81-3, NUDOCS 8106010706 | |
| Download: ML20004C185 (15) | |
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UNITED STATES
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E REGION 11 i
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o 101 MARIETTA ST N.W.. SUITE 3100 ATLANTA, GEORGIA 30303 o
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- ,,,e Report No. 50-338/81-05 and 50-339/81-03 Licensee: Virginia Electric and Power Company P. O. Box 26666 Richmond, VA 23261 Facility Name: North Anna Docket Nos. 50-338 and 50-339 License Nos. NPF-4 and NPF-7 Inspection at North Anna Site,iear Mineral, VA Inspectors M
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Approved by (.
W H. C. Dance, section Chief, Division of Dat(Sygned Resident and Reactor Project Inspection SUMMARY Inspection on February 1 - March 5,1981 Areas Inspected This routine inspection by the resident inspectors involved 205 inspector-hours on site in the areas of refueling activities, maintenance, surveillance, turbine rotor replacement, RCS flow splitter inspection, staffing, TMI Task Action Plan,
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conduct of operations, drawing control, reportable event and IE Bulletin 80-24.
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Results Of the eleven areas inspected, no violations or deviations were identified in nine areas. Three violations were identified in two areas (Failure to assure corrective actions are coepieted paragraph 7.b; failure to follow procedures
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for setpoint changes paragraph 7d; ard failure to evaluate setpoint changes per
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10 CFR 50.50 paragraph 7d).
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DETAILS 1.
Persons Contacted Licensee Employees
- W. R. Cartwright, Station Manager
- E. W. Harrell, Assistant Station Manager
- D. L. Benson, Superintendent, Techncial Services J. R. Harper, Superintendent, Maintenance S. L. Harvey, Superintendent, Operations J. M. Mosticone, Operations Coordinator
- J. P. Smith, Engineering Supervisor R. A. Bergquist, Instument Supervisor
- F. Terminella, Engineering Supervisor A. K. White, Engineer
- H. L. Travis, NDE Engineering Supervisor Other licensee employees contacted included three technicians, five operators, and several office personnel.
Other Organizations Westinghouse Nuclear Services Division G. Williams, Resident Westinghouse Engineer
- Attended one or more exit interviews 2.
Exit Interview The inspection scope and findings were summarized on February 6, 20 and 27, 1981 with those perstns indicated in paragraph 1 above.
The violations identified in paragraphs 7b and 7d were discussed and acknowledged on February 20.
The violation discussed in paragraph 6a was explained on February 27 as not resulting in a Notice of Violation based on licensee identification, reporting and correction of the cause.
3.
Licensee Action on Previous Insoection Findings (Closed) Unresolved Item (339/81-01-02) High incore detector background a.
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readings. The followup to this item is discussed in detail in para-graph 7b.
The unresolved item is closed, but new item numbers l
(338/81-05-06 and 339/81-03-05) are opened on the violations and l
generated during the followup inspection.
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b.
(Closed) Unresolved items (338/80-30-03 and 339/80-29-09) Vendor manual control. This issue was resolved in IE Report 338/80-26 and 339/80-31.
Subsequent licensee commitments identified in letter Serial No.1016A dated February 12, 1981 shall be followed up (338/80-26-01 and 339/80-31-05) in future inspections.
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Unresolved Item; Unresolved items were not identified during this inspection.
5.
Unit 1 During this reporting period, the second refueling outage continued for Unit 1.
The outage started December 27, 1980 and is presently scheduled for completion March 22, 1981.
During February, fuel was reloaded into the reactor vessel and the reactor coolant system reclosed. Major maintenance activities included:
replacement of the number 2 low pressure turbine rotor, installation of main generator output breakers, fire protection modifications, and seismic support rework, a.
Fuel Handling During the inspection fuel was loaded in Unit 1 for Cycle 3.
Portions of this evolution were observed as well as the activities leading up to the fuel movement. The following Periodic Tests (PT) were reviewed to determine compliance with Technical Specifications during fuel move-ment:
Manipulator Crane (1)
1-PT-38.1.2, Containment Area Monitor
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(RMS-162) Funtional Test (2)
1-PT-38.1.5, Containment Particulate Monitor (RMS-159) Functional Test (3)
1-PT-38.1.6, Containment Radio Gas Monitor (RMS-160) Functional Test (4)
1-PT-13.3, Boration System F1.ow Path Verification (5)
1-PT-14.1, Charging Pump 1-CH-P-1A (6)
1-PT-15.1, Boric Acid Transfer Pump - (1-CH-P-2A) Test (7)
1-PT-92.1, Manipulator Crane (Hoist)
(8)
1-PT-92.2, Manipulator Crane Aux Hoist (9)
1-PT-93, Water Level - Reactor Vessel (10) 1-PT-89.2A, Fuel Oil Analysis
"A" Tanks and other Misc. Tanks (11) 1-PT-89.2B, Fuel Oil Analysis
"B" Tanks and other Miscellaneous
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Tanks The inspector noted that personnel manning was in accordance with l
established requirements, up to date copies of the approved procedure
were available, the procedure was in use and was being followed and
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communications were in use as required. The inspector had no questions concerning this evolution.
b.
Containment Penetration Testing The inspector reviewed 1-PT-61.3, Rev 2, Containment Type C Test, and observed a portion of the test where penetration 108 was tested. The inspector noted that there was no guidance given to the operator as to how to shut the manual containment isolation valves under test.
Review of 10 CFR 50 Appendix J identified only that valves should
"...be closed by normal operation and without any preliminary exercis-ing or adjustments...". Discussions with the operators responsible for the performance of the testing showed that they followed this guidance and understood that no means of exerting high torque on the valve was allowed. This lack of guidance was reviewed with plant management and it was suggested that 1-PT-61.3 be revised to include the guidance given in Appendix J and specifically reference it to manual valves.
This item will be identified as inspector followup items 338/80-05-01 and 339/80-03-01.
c.
Turbine Inspection and Rotor Replacement The licensee conducted cn ultrasonic examination of the Unit 1 main turbine low pressure disc in accordance with the Atomic Safety and Licensing Appeal Board (ASLAB) Order of November 18, 1980 during the second refueling outage in January 1981.
The results of this examination was reported to IE orally on January 15 and a formal report, dated January 16, 1981, was provided to the ASLAB.
IE Report 338/81-02 identified item 338/81-02-05 for followup of crack indica-tions found, during this examination, in the No. 2 low pressure turbine rotor discs.
The licensee procured a replacement turbine rotor from Metropolitan Edison Co. This replacement rotor was ultrasonically examined at the Three Mile Island facility and once determined to be acceptable, shipped to North Anna.
The rotor assembly arrived on site on February 20, 1981 and was still being installed at the close of this reporting period.
On February 23, the ASLAB issued a Memorandum and Order approving resumption of Unit 1 operation, when the l
NRC staff is satisfied with the replacement rotor installation.
Review of receipt inspection data and installation shall be the subject of future inspections (338/81-02-05).
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d.
Flow Splitter Inspection As a result of cracking detected in the Unit 2 reactor coolant pump
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section flow splitters in March 1979, Amendment 10 tc license NPF-4 was
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issued on Aoril 27, 1979 requiring examination of the Unit 1 flow splitter plates every 18 months (not to exceed 22.5 months).
On February 17 and 18, the licensee conducted ultrasonic tests of all
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three flow splitters and identified six indications on the A loop plate (wall side) and several less significant indications in the other five examinations.
Reinspection of all three plates on February 23 and 24 confirmed these indications, and supplied accurate baseline data for future examinations.
On February 27, the licensee and Westinghouse Electric Corporation presented this data plus material stress analysis conclusions to the NRC.
The analysis, confirmed by proprietary Japanese empirical data, indicates that: (1) since no indications exist at the edges of any of the plates, the plates have not failed (2) if these indications are cracks, they will propagate toward the edges of the plate, which will
.be identifiab.le infuture inspections and (3) once the cracks reach the edges or the plates the stresses will be relieved and the plate will not break apart.
The findings were acknowledged by NRC and based on this, NRC accepted the licensees position that this represents no safety concern affecting resumption of operations.
However, the NRC staff requested the licensee forward a letter committing to (1) reinspecting the flow splitters by ultrasonic techniques during the planned outage in November and (2) continue the augmented loose parts monitoring system inspection program recommended by Westinghouse and required by the NRC Confirmation of Action letter dated February 26, 1980.
Item (338/81-
-05-02) is identified to followup on completion of the inspection in November 1981.
6.
Unit 2 During this reporting period, Unit 2 was operated at capacity load.
The unit tripped from 100% power on February 3 due to an operator error in conduct of a surveillance test. The unit was returned to power the same day.
a.
Battery Surveillance On February 20, 1980, licensee management informed this office of a difficulty in meeting the written requirements of Technical Specifi-cation 4.8.1.1.3.b for the emergency diesel generator batteries. Based on the results of periodic test 2-PT-86 completed February 18, fifteen battery cells for the 2J diesel and 6 for the 2H diesel demonstrated individual cell voltage (ICV), decreases of greater than 0.05V since the previous surveillance conducted December 1,1980.
The surveillance results for February indicated that none of the cells, so identified had low specific gravity, and all were within 0.03 volts of the ' Float Voltage' for the battery. The difficulty appeared to be caused by the abnormally large spread of ICVs (2.18 to 2.29) in the December suveillance. The licensee identified the basic problem as being the lack of consistency in the equalize charging of these batteries prior to conducting this surveillance and committed to revise
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the procedures to properly schedule and detr.1 the procedure for charging all batteries by April 15, 1981, prior to conduct of the next surveillance.
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The licensee also elected to recharge both of the diesel battery banks and repeat the surveillance on February 23.
Results of 2-PT-86 for that date showed all cells to have sufficient specific gravity and to be within specified ICV limits.
In a more thorough review of the battery surveillance procedures, the inspector identified the following deficiencies:
1)
No procedure exists to charge the batteries.
2)
PT-86 requires only a sampling of cell temperatures be taken and averaged for correction of all specific gravities.
In several instances, when the cell temperatures ranged over 5 or 6 degrees Fahrenheit, some cells with specific gravities near 1.200 (the low limit) may be incorrectly analyzed because of the temperature correction.
3)
The procedure for evaluating ICV trends from one test to the next is not formalized. Since battery float voltages (and, therefore ICVs) vary from 127 to 136 volts, the ICV readings need to be normalized first, a step which is not indicated in the procedure.
The licensee committed to resolving the above deficiencies by April 15, 1981 (338/81-05-03) and 339/81-03-02).
The failure to implement and maintain a procedure to charge vital DC bus batteries and diesel batteries is in violation of Technical Spec-ification 6.8.1.a., however, a Notice of Violation is not forwarded since:
the licensee had identified the violation, will be reporting
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the event, the violation is severity level V as identified by NRC Enforcement Policy, and corrective action is being taken in a reason-able period of time.
Followup of this item shall be tracked (338/81-05-04 and 339/81-03-03).
b.
Pressurizer Backup Heaters While reviewing various administrative controls the inspector noted that Standing Order 69 described a problem with two of the four pres-surizer backup heater groups. The problem described was with Groups B and D where the cable between the main line contactor and the heater breaker panel is undersized. This causes higher heat generation and during periods of high ambient temperature one, or more of the heater breakers may trip causing the loss of a portion of the group's heater capacity. The Standing Order recommended varying the heater groups in service so as to reduce the time one heater group was energized. A review by the inspector determined that Pressurizer Heater Group D was
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one of the groups powered from an emergency bus and required to be available in order to maintain pressure control while in natural circulation.
This requirement, item 2.1.3.1 of NUREG 0578, was also discussed in VEPC0 letters #760 of 10/24/79 and #906 of 11/26/79 where it was stated that a minimum of 125KW was required by the NSSS supplier to insure adequate control in natural circulation. The trirping of the heater breakers could reduce the group heater capacity below that required. After discussion of this problem with plant aanagement, a jumper was installed which opened one of the heater creakers and reduced the current to below that recommended for the cable size. This will prevent overheating of the cable due to excessive current but will not reduce the heater capacity to less than the minimum of 125KW.
Jumper #222 was reviewed and its installation verified on Unit 2.
Final corrective action will be the installation of larger cable from the contactor to the breaker panel. Inspector followup items (338/81-
-05-05 and 338/81-03-04) will track completion of the permanent change.
7.
Both Units / Site a.
TMI Task >.ction Verification 1)
Task II.F.2, item 1. Installation of subcooling monitors (Unit 1 only).
In a letter dated April 23, 1980, the NRC Office of Nuclear Reactor Regulation accepted the actions taken by VEPC0 at North Anna 1 to fulfill the Categcry "A" items of the TMI Lessons Learned.
Paragraph 2.1.3.b of the staff's evaluation required that the wide range pressure sensors be upgraded to safety grade by January 1,1981.
The inspector reviewed the below listed documents to ascertain the design qualifications of the reactor coolant system wide range pressure channels P-1402, P-1403, P-2402, and P-2403:
a)
NPSQAM Section 2 c)
Design Change 79-S65 A and B d)
Design Change 80-518 e)
FSAR Tables 8.3,1-2 and 8.3.1-3 f)
Drawings:
11715-FE-7BW, 11715-E-1270, 13075-K-42, 13075-FE-3MA, 11715-P-1402, 11715-P-1403, 12050-P-2402, and 12050-P-2403 g)
Reg Guide 1.97 Rev 2
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VEPCO letter serial #536 of July 7,1980 w
Based on design data and drawing information, the inspector verified that the wide range pressure channels meet all of the requirements for a protection system in IEEE standard 279-1971 and the requirements in RG 1.97 Rev 2, Table 1.
Further, since the April 1980 letter, RG 1.97 Rev 2 was published which does not require the inputs to the subcooling monitor be safety grade.
ONRR was informed of this finding by telephone and the Licensing Project Manager agreed with the conclusion.
Items (338/80-38-07 and 339/80-36-07) are closed and Task II.F.2 item 1 is considered closed.
2)
Task I.A.1.a Shift Technical Advisor (STA) manning and training.
This item requires fully qualified STAS be assigned'to operations by January 1,1981.
The inspector reviewed the results of a final examination given to the eight of the STA applicants at the completion of the STA training program in December, 1980. Two of the applicants failed the examination with grades of 66.6 and 63.8 (70 passing). One of those individuals was performing STA duties and was removed from those duties on January 25, 1981. The remaining 8 persons include the SES supervisor, an engineering supervisor and two engineers presently assigned to the engineering staff. The four STAS are on.
a rotating duty basis such than an STA is always on site. The two individuals who did not take the exam have SR0 licenses and are
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j current in their requalification program.
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received the STA trainirg program. Records included the two exams given, but had no indication of program completion or qualifi-cation as STAS. Training department staff indicated they were working on establishing certification documentation for STAS.
This will be followed up in future inspections under numbers already identified for Task I.A.1.1 (338/80-38-01 and 339/80-36-
-01).
3)
Task I.C.5 Procedures for feedback of operating experience to plant staff.
IE Report 339/80-10 paragraph 7 discussed the licensees independent safety assessment capabilities as of Februar.) D80 and identified item (339/80-10-06) to followup on development of the system.
Since that time, the licensee identified the program in letter serial #277 dated March 26, 1980 and established a corporate level Safety Engineering and Control (SEC) staff and a plant level Safety Engineering Staff (SEST.
The Safcty Engineering Staff Administrative Procedures Manuai (revision 1) dated August 29, 1980 promulgates the corporate and plant urogram, specifying
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organizational requirements for review, evaluation, and trans-mission of nuclear industry information.
The SES is tasked to
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provide information, which is considered urgent, directly to
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operations staff via the Shift Technical Advisors (STA).
Otherwise the SES provides the information to the training department for inclusion in the requalification training program.
Evaluation of information and engineering reviews are coordinated between the SEC and SES and require second reviews prior to transmittal either to the staff or to outside organizations. The inspector discussed this program with SEC and SES staff, reviewed the qualifications of the staff members of each organization and had no further questions in this area.
Item (339/80-10-06) and Task I.C.5 are considered closed.
b.
Axial Power Distribution Monitoring As discussed in IE Reports 338/80-41, 339/80-38, 338/81-02, and
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339/81-01, the licensee Axial Power Distribution Monitoring System (APDMS) does not subtract incore detector background readings from the peak readings in the calculation of Fj(z). In the licensee's letters, i
serial #0248 and #024C of February 16 and 27, 1979, respectively, corrective action to insure conservative operation of the APDMS was identified to 1) lower the ADDMS limit setpoint to account for detector background and 2) implement administrative procedures requiring the reactor operator to review the flux traces used by the APDMS in order to characterize detector background.
i As discussed in IE Report 338/80-41 and 339/80-38, paragraph 9, the limit setpoints are lowered by manual calculation during flux map
analysis (a corporate function).
i Following up on the high detector background concern discussed in IE Report' 338/81-02 and 339/81-01 (evaluation of the cause of the high background readings in map N2-126 and final corrective action is
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r considered unresolved (339/81-01-02). however,' the inspector found
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that administrative procedures do not exist requiring flux trace review
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for detector background during APDMS operation or during flux mapping.
The high detector background alarm functions ard procedural controls in procedure PT-26.3 for conduct of "FQ Survey" computer program would
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only identify high detector background i f the ' APDMS system were inoperable, requiring the FQ Survey surveillance to be run.
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normal plant operation, only the flox map, run every 31 days, wbJld
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identify the detector background level as being high (above 0.01) or trending toward a 0.01 reading.
Surveillance procedures for neither unit (1-PT-21.1 and 2-PT-21.1) for flux mapping identify detector background levels of 0.01 as a limit for detector operation on APDMS, or even require review of the data.
The licensee committed to change the manner in which APDMS is run and to revise the procedures to insure the encore detector traces are evaluated. A more complete discussion of these actions is presented in
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IE Report 338/81-03 and 339/81-02, and requires no further response from the licensee.
The fe 1ure to complete the corrective actions committr.d to in licensee letters of February 16 and 27,1979 for Unit 2 and the failure to establish administrative controls which adequately identifies high incore detector background readings to assure that dctectors exhibiting such characteristics are removed from APDMS use is a violation (338/81-05-05 and 339/81-03-05) of 10 CFR 50 Apper. dix B Criterion XVI, which requires measures be established to assure that the cause of a significant condition adverse to quality is determined and corrective actions taken to preclude recurrence. Chapter 16 of the Nuclear Power Station QAM, Section 5.8 only vaguely addresses QA followup of identi-
,fied corrective action, but no mechanism has existed for assuring adequacy of actions taken.
The lack of measures to assure that corrective actions, specifically when programatic or administrative in nature, have been properly identified and corrected has been the source of several recent NRC identified violations.
For administrative purposes, items (338/79-01-03, 339/81-01-02 and 339/79-01-3) are closed concerning this same issue.
The issue of reportability on the high incore detects background reading obtained on flux map N2-126 (Reference IE Report 339/81-01, paragraph 6) is also resolved as the licensee did not consider APDMS operable for Unit 2 until mid January 1981.
c.
Staff Qualifications Owing to the personnel changes in station management over the last year, the inspector reviewed the training files of eight station supervisors and superintendents.
The background experience levels, education, and completed training was compared to the following
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l requirements: Technical Specification 6.3.1; ANSI N 18.1-1971; Reg Guide 1.8, September 1975; and ANSI N 45.2.6-1973.
All personnel checked were found to meet the requirements of the applicable standards above.
It was noted to plant management, that the Health Physics Supervisor's, 13 years of training and experience in the radiation protection field qualifies as equivalent to the 4 year degree require-ment of Reg Guide 1.8.
The inspector had no further questions in this area.
d.
Setpoint Change Program During this inspection period the Setpoint Change Program and Setpoint Changes made during 1978,1979 and 1980 were reviewed. The Setpoint l
Change Program was reviewed against requirements of 10 CFR 50.59 and
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Appendix B and the programs implementation against the stated require-ments in the Nuclear Power Station Quality Assurance Manual Section 6.
The following is a list of the documents reviewed:
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1)
Nuclear Power Station Quality Assurance Manual
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Setpoint Change Requests 78-01, *78-02, *78-03, 78-04, *78-05, 78-06, 78-09, 78-11, 78-13', 78-14, *78-15, *78-16, 78-17, 78-18, 79-01, 79-02, 79-03, 79-04, *79-05, 79-06, 79-07, 79-08, *79-09,
- 79-10, 79-11, 79-12, *80-01, *80-02, *80-03, *80-04, *80-05, 80-06, 80-07. These identified with an asterick require safety evaluations.
The specific results of this review were provided to the Emergency Supervisor. The general findings are recorded in the following para-graphs.
The procedures governing the generation, review, approval, implement-ation and documenting of a setpoint change request are covered in the Nuclear Power Station Quality Assurance Manual Section 6 and Engineering Administrative Procedure #1 and #2. However, no require-ment exists in this program to req' ire a safety evaluation to determine u
if an unreviewed safety question does exisc as required in 10 CFR 50.59. Eleven change requests of safety system were identified as not having a safety evaluation documented. The failure to require a safety evaluation is a violation of 10 CFR 50.59 and is designated 339/20-
- 05-07 and 339/80-03-06, The implementation of the program was inspected by review of the Setpoint Change Requests for 1978, 1979 and 1980. This.eview showed that there were numerous examples of failing to record the implement-
,ation of the setpoint change on the Setpoint Change Request, failing to complete the Controlled Document Review and Revision form, and failing to forward completed Setpoint Change Requests to Station Records.
Failure to complete these actions present proper review and' changes to engineering documents.
These examples are a violation of 10 CFR 50 Appendix B Criterion V which requires activities affecting quality to be accomplished in accordance with approved procedures and is l
designated 338/80-05-08 and 339/80-03-07.
e.
Control Room Annunciators The process of reviewing the Control Room Annunciators was continued during this inspection period.
This program reviews the electrical l
elementary drawings, Annunciator Response procedures and setpoint l
- documents discrepancies are noted and discussed with plant management.
During this period, the following annunicators, elementary drawings, and Annunciator Response procedures (AR) were reviewed:
1)
RCS, PORV, TKA, N Sup, L Press (358/53) on 1-EI-CB-21C,
ESK-10e, Sh2, R12, ESK-10AAJ RIO, AR-1C-E7 dd 3/26/80.
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RCS PORV TKB N Sup. L Press (359/62) on 1-EI-CB-210, ESK-10C SHZ
R12, ESK-10AAJ RIO, AR-1C-F8 dtd 3/26/80 l
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SFGDS B CONT to Aux SHUTDWN PNL (410/54) on 1-EI-CB-Z1K, ESK-10 BAA R10, AR-1K-F7 dtd 2/7/77 4)
SFGDS A CONT to A:x SHUTDWN PNL (379/62), ESK-10K-SHZ RB, ESK-10 AAZ R7, AR-1K-F8 dtd 2/7/77 5)
SW Loss of CONT PWR (489/36) on 1-EI-CB-21J; ESK-10J SHZ R13, ESK-10 BAF R7, AR-1J-05 dtd 1/24/77 6)
1-I INVERT TROUBLE (597/1) on 1-EI-CB-21H; ESK-10H Sh1 R14, ESK-10BAJ R9, AR-1H-Al dtd 1/24/77 7)
1-II INVERT TROUBLE (598/9) on 1-EI-CB-21H, ESK-10H SH1 R14, ESK-10BAJ R9, AR-1H-A2 dtd 1/24/77 8)
1-III INVERT TROUBLE (599/17) on 1-EI-CB-21H, ESK-10H SH1 R14, ESK-10BAJ R(, AR-1H-A3 dtd 1/24/77 9)
1-IV INVERT TROUBLE (600/25) on 1-EI-CB-21H, ESK-10H Sh1 R14, ESK-10BAJ R9, AR-1H-A4 dtd 1/24/77 10) RWST CHEM ADD TK LO LEVEL (268/10) on 2-EI-CB-21J, ESK-10J Sh1 R8, ESK-10AAU R5, AR-2J-82 dtd 4/2/79.
11) HEAT TRACING TROUBLE (289/55) on 1-EI-CB-21A, ESK-10AAV RIO, AR-1A-H7 12) EMPTR ALARM PRTILT ROD DEV/ SEQ (170/28) on 1-EI-CB-21A; ESK-10AAK,1-AR-1A-2C dtd 11/17/76 13) R0D BANK A LO/LO-LO LIMIT (300/8) ON 1-EI-CB-21A: ESK-10AAK R&,
i 1-AR-1A-87 dtd 7/16/79
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Questions identified during this review were all minor in nature and l
have been referred to the Superintendent of Operations for evaluation
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and resolution.
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f.
Drawing Control While reviewing the controlled set of FM drawings in the Control Room the inspector noted that a red line update to L1715-FM-72A-12 Valve
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Operating Numbers Auxiliary Steam and Air Removal Sheet I had been l
indicating that Design Change 80-41 had been completed. This red line update is required to be completed during the technical review of the
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l Design Change and before declaring the equipment operable. This is in accordance with the Nuclear Power Station Quality Assurance Manual (NPSQAM) Section 3 paragraph 5.8.1.
Further review determined that DC80-41 had not been completed and the update had been made in error.
The drawing was immediately corrected.
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The inspector also noted that there were no instructions to the Opera-tions Administrative Assistant concerning transferring red line infor-mation from old revisions to new revisions of FM drawings as the Control Poom drawing are updated. After discussion with plant manage-ment,it was agreed that administrative guidance would be implemented
for this requirement. This item is designated as inspector followup item 338/80-05-09 and 339/80-03-08.
g.
IE Bulletin 80-24 Water Lenkage Inside Containment IEB 80-24, issued November 21, 1980 addressed problems associated with water leakage inside containment from open cooling systems which n
results in wetting the reactor vessel.
The licensee's response dated January 5,1981 indicated that the one-open cooling system in containment (service water) is isolated and administratively controlled during normal operation, and would only be
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used under accident conditions where a containment high pressure condition exists.
Further owing to the elevation of the reactor vessel, numerous indications of flood conditions already exist to identify flooding prior to wetting the reactor vessel.
The inspector reviewed the licensees containment design and sump level.
sump pump, sump pump flow, and surveillance procedueres to verify adequate' indications exist to assure indication of flooding.
The licensee's containment sump level indication system is a safety grade two float sensor system which is calibrated each refueling. One of the two level sensors also operates sump pumps DA-P-4A and DA-P-4B to pump the sump to the liquid waste system via a flow totalizer. The flow totalizer is also calibrated every refueling and is required by Technical Specifications to monitor reactor coolant system leakage (every twelve hours).
Should both of these indicators, which display level in the control room and alarm on high level, fail, the containment floor on the 231'
elevation is trenched from the normal sump to the emergency sump, which has two more level indicators, indication 0-10 foot level (about 600,0C0 gallons) in the control room.
These indicators are not presently calibrated on a periodic surveillance schedule, however, because of the TMI task item II.F.1.5 requirements for sump level indication, shall be on a periodic calibration schedule by January 1, 1982. (Items 338/81-05-10 and 339/81-03-09).
These level indication channels were recently recalibrated due to relocation of the level transmitters.
Directly below the reactor vessel is an incore instrumentation sump with a single electrode type level indicator system which controls a sump pump and alarms in the control room on Hi level (sump pump start)
and Hi-HI level. This instrument is not checked on any periodicity and uses a single pump to transfer fluid from this sump to the normal containment sump. Upon discussion of the reliability of this system,
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the licensee committed to revise the pre-startup containment inspection procedure OP-1B, to include inspection of this space prior to startup from the present outage, and to evaluate sump level instrument sur-veillance. These will be followed up (338/81-05-11 and 339/81-03-10).
8.
Plant Tours Tours of various plant areas were conducted during the inspection period in conjunction with other inspection activities.
The following items, as available, were observed:
a.
Fire Equipment Operability and evidence of periodic inspection of fire suppression equipment..
b.
Housekeeping Min n..al accumulations of debris and maintenance of required cleanliness levels in systems under or following testing.
Observations regarding certain areas were given to station management who acknowledged the inspector's comments.
c.
Equipment Preservation Maintenance of special preservative measures for installed equipment as applicable.
d.
Component Tagging Implementation and observance of equipment tagging for safety ov-equipment protection.
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Communication Effectiveness of public system in all areas toured.
f.
Equipment Controls l
Effectiveness of jurisdictional controls in precluding umuhorized work or systems turned over for initial operations or prewerational
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Maintenance of controls to assure systems which have been cleaned and flushed are not reopened to admit foreign material.
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Implementation of security provisions for both Units.
i Within the above areas, no items of noncompliance or deviations were s
l observed when compared to the applicable station program and procedures.
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