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Insp Repts 50-413/89-09 & 50-414/89-09 on 890410-0505. Violations Noted.Major Areas Inspected:Various Plant Groups Including Operations,Maint,Qa,Engineering & Training in Support of Safe Plant Operations
	ML20246P732
Person / Time
Site:	Catawba
Issue date:	07/10/1989
From:	Russell Gibbs, Lawyer L; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20246P695	List: ML20246P689; ML20246P705; ML20246P732;
References
	50-413-89-09, 50-413-89-9, 50-414-89-09, 50-414-89-9, NUDOCS 8907200297
	Download: ML20246P732 (86)
	v • d • e

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4J yg Miho UNITED STATES

J- 'o - NUCLEAR REGULATORY COMMISSION

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L . Report Nos.: 50-413/89-09:and 50-414/89-09

' Licensee: Duke Power Company 422 South Church Street- Charlotte, NC.28242 Docket No.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-52 Facility Name: Catawb'a 1 and 2 Inspection Conducted: April 10-May 5,1989, Exit Conducted: May 16, 198 ; Inspectors- [

p . Mbbs;. Team Leader R

Yl, 7 i ti rd)

Datp'Sitned

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M . Lawyer, Team Leader (EOPs)

W)v tn Yi Datp S t'gned Team Members- R. Bernhard G. Bryan, J M. Ernstes G. Maxwel'

R. Musser S. Ninh C. Pau',k'

G. Cn yer R. Schin A. Sutthoff Accompanying Personnel: Arie de Joode, Ministry of Social Affairs

_ d7Em ment, Nuclear Department, The eth nd /

Approved by: '

- dm/ /0,/9 W W P."Kellogg, Chief .-

/ . /Date 'Signec Operational Programs 4 tion Operations Branch Division of Reactor Safety

. SUMMARY Scope: This was a special announced Operational Safety Team Inspection (OSTI). The OSTI evaluated the licensee's current level of perform-ance in the area of plant operations. The inspection included an evaluation .of the effectiveness of various plant groups including Operations, Maintenance, Quality Assurance, Engineering, and Training in support of safe plant operations. Plant management's awareness of, involvement in, and support of safe plant operation were also evaluate *

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i The inspection.was divided into three major areas including Opera-tions, Support of Operations, ' and Emergency Operating Procedure The. team placed emphasis on interviews -of ' personnel at all levels, observations of plant' activities and meetings, extensive . control room observations, and system walkdowns. The team also reviewed plant deviation' reports, LERs for the. current SAlp evaluation period, and'

evaluated the effectiveness of the licensee's root cause identifica-tion; short term and programmatic corrective actions, and repttitive ~

failure. trending and related corrective action Results: The 'overall assessment concluded that the site is well-managed. The Emergency 0perating Procedures were determined to adequately cover the broad range of- accidents and equipment failures necessary. for safe shutdown of the plant. Only minor problems were found by the team. A

. summary of the weak areas and strong areas observed by the. team are as follows:

Weaknesses:

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Management used verbal instructions to modify safety related proce-dures for cold leg accumulators instead of . issuing a comprehensive written procedure. (paragraph 2.a.) (IFI 413,414/89-09-02)

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Controis on-the thermal power computer and its inputs are weak. This computer' is used for normal determination of plant power level and for. adjusting the gain on the nuclear instruments. (paragraph 2.b.)

(IFI 413,414/89-09-03)

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0ne '10 CFR 50.59 evaluation was weak concerning a modification to the nuclear service water pit strainer instrumentation. Annuncia-tors' described in the FSAR were disabled for about 30 days with no written . consideration of compensatory actio (paragraph 2.c.)

(IFI 413,414/89-09-04)

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.Many of the site's safety related pump rooms are contaminated, which'

l inhibits operator and management surveillance. (paragraph 2.e.)'

(IFI 413,414/89-09-05)

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Auxiliary operators on rounds failed to frisk immediately after exiting contaminated areas. (paragraph 2.e.) (VIO 413,414/89-09-01)

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Control of doors was weak, as indicated by the three open fire or security doors found by the team. (paragraph 2.g.)

(IFI 413,414/89-09-06)

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In the Independent Verification and Safety Tag procedures, three I items for potential improvement are identifie (paragraph 2.1.)

(IFI 413,414/89-09-07)

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Valve 1-KC-9 (component cooling water pump 1A2 dischars e valve) which is required to be locked by site procedures was found not locked during system walkdow (paragraph 2.k.) (VIO 413,414/89-09-01)

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Several deficiencies were noted during observation of a performance test on one of the containment spray pumps. (paragraph 2.m.)-

(IFI 413,414/89-09-08)

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Scaffolding procedures do not address seismic considerations and resultant inoperability of safety equipment. (paragraph 2.r.)

(IFI 413,414/89-09-09)

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I&E maintenance does not use portable equipment to facilitate timely locating of de ground faults. (paragraph 2.s.) (IFI 413,414/89-09-10)

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There are many significant deviations between the E0Ps and the PSTGs (Plant Specific Technical Guidelines) where there should be non This is primarily due to changes being made in the E0Ps before being made in the guidance document (PSTG). (paragraph 3 and Appendix B)

(IFI 413,414,/89-09-11)

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There are many technical and human factors discrepancies that were identif:ed in the E0P Each one is listed. (paragraph 3.b. and Appendix B) (IFI 413,414/89-09-12)

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Many labeling discrepancies between E0Ps and panel indication were identifie Each one is listed. (paragraph 3.c. and Appendix D)

(IFI 413,414/89-09-13)

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There is a discrepancy between the E0Ps and the S/G pressure meter in the control room. (paragraph 3.c.) (IFI 413,414/89-09-14)

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Many writer's guide discrepancies were identified in the E0Ps. Each one is listed. (paragraph 3.c. and Appendix C) (IFI 413,414/89-09-15)

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Noise level in the control room during auto-start of both ventila-tion trains during S/I response is excessive. (paragraph 3.c)

(IFI 413,414/89-09-16)

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Deficiencies were identified in simulator effectiveness in training on E0Ps (paragraph 3.d) (IFI 413,414/89-09-17)

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There were weaknesses noted in the site's ETQS program. (paragraph 4.a.) (IFI 413,414/89-09-18)

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There are approximately 131 temporary modifications in effect on sit Some date back as far as 3 or 4 years. (paragraph 4.c.)

(IFI 413,414/89-09-19)

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The separate reporting authority and duplication of support functions I for the Transmission Group is considered a weakness. (paragraph 4.j.) l (IFI 413,414/89-09-20) l

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, Strengths:

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Shift turnovers were efficient and effective.- (paragraph 2.d.)-

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Centrol' room decorum was good, with orderly appearance and proper

' beha vi o r.' (paragraph 2.d.)

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.0perators displayed a professional attitude toward their responsibi-11 tie (paragraph 2.d.)

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Operator control of access to the control room was good. (paragraph 2.d.)

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. Housekeeping in general was very good, but there were. some excep-tion (paragraphs 2.e. and 2.h.)

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Inside ' and outside auxiliary operator rounds were very thoroug (paragraphs 2.e. and 2.h.)

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Labeling overall ' was very good, with the exceptions of ' auxiliary building doors and instrument root valve (paragraphs 2.e., 2.j.,

and 2,k.)

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On theiriown intitiative, the licensee is upgrading the seismic-l safety margin of. the diesel generator batterie (paragraph 2.f.)'

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There was good feedback from site personnel on management involvement f <

in solving. problems. (paragraph 4.a 4.e and 4.k)

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Operations has a daily input into the MWR backlog for prioritizing work item (paragraph 4.g)-

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-The planners inspection of the worksite prior to initiation of the MWR package is considered a strength. (paragraph 4 h). .

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Rotation of .,ork shifts together provides for a smoother flow of work. (paragraph 4.h)

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The practice of. working items by train or division in a weekly rotation helps limit problems of having 2 trains inoperable at the same time. (paragraph 4.h)

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Plant meetings were brief, to the point, and provided adequate plant status to involved management personne (paragraph 4.1)

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The new 10 CFR 50.59 training for site personnel is thorough and meaningful. (paragraph 4.1)

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Changes to the Catawba Critical Safety Function integrity tree are considered to be significant enhancements which are supported by valid deviations from the ERG. Catawba treatment of the coolant integrity tree ' was excellent, particularly with ' respect to cold overpressure protection. (Appendix B)

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?A' .s REPORT DETAILS ~

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l Persons. Contacted

Licensee employees K. Alcorn, Reactor Operator J. Barbour, QA Director Operations

H. Barron, Superintendent Operations W. Barron, Director of Operations Training T. Beadle, Procedures Engineer-

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W. Bradly, QA Verification Manager

. R. Casler, Shift Operations Manager

- J. Cox, Production Support

T. Crawford, Superintendent Intergrated Scheduling M. Criminger, QA Verification Specialist II R. Edmund, Reactor Operator p J. Effinger, QA' Verification Specialist II- Audit J. Frye, QA Verification Manager -Audit

R. Gill, Corporate Compliance Manager-J. Glen, Production Engineer

M. Glover, Compliance Manager C. Graves, Operations,~ General Office

T. Harrall, Sr. Project Engineer, Design Engineering D. Jenkins,' Design Engineer R. Kimray, Senior Instructor

V. King, Production Engineer

J. Knuti, Operations Support Manager M. Lee, Nuclear Control Operator P.. LeRoy, Compliance, General Office

W. McCollum, Superintendent Maintenance K. Munk, Reactor Operator C. ' O' Dell, Shift Supervisor

T. 0 wen, Station Manager ;

G. Rhyne, Nuclear Equipment Operator M. Sanders, Nuclear Equipment Operator L. Saunders, Reactor Operator K. Seasely, Procedures Engineer G. Swindlehurst, Engineering Supervisor

- Thompson, Senior Reactor Operator G.'Winkel, Simulator Instructor Other Licensee employees contacted included instructors, engineers, mechanics, technicians, operators, and office personne NRC Representatives

E. Merschoff, Deputy Director, DRS, Region II

W. Orders, Senior Resident Inspector

M. Lesser, Resident Inspector

B. Bonser, Project Engineer, Region II

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K. Jabbour, Project Manager

Attended exit interview Acronyms used throughout this report are listed in Appendix ' Operations (41400, 41707, 61700, 71707, 93802)

Many of the positive attributes of operational safety can be directly observed in the control room. These attributes include such things as adequate shift manning, delegation of Shift Supervisor (SS) non safety related duties, Reactor Operator (RO) and Senior Reactor Operator (SRO)

system knowledge, relief turnover procedures, etc. Adequate shift manning assures: qualified plant personnel to man the operational shifts are readily available and that excessive overtime need not be utilized; delegation of nonsafety-related duties assures the SS attention to the command function will not be diverted to nonsafety-related duties; and accurate diagnosis and response to plant transients, minor and major, require detailed operator systems knowledge, et Other operational safety attributes can be better assessed through plant tours and system walkdowns. These include material condition; conformance to approved procedures; attentiveness to duties; and return to service of

. equipment important to safety, including correct system alignment Finally, interviews with personnel holding a variety of positions on the plant staff together with some review of records is necessary to provide indirect indicators of operational safety and to corroborate preliminary assessment To assess the operational safety of the facility, the team performed extended observations of control room activities, including back shifts, with the units in modes 1, 5, and 6. Also, the team conducted system walkdowns and plant tours. In addition, they interviewed operators during these observations, walkdowns, and tours, observed shift turnovers, and reviewed operator logs. The team also reviewed records used for indica-tion or control of plant status for adequacy and verified operator aware-ness of their contents. These included the LCO Log, configuration contisi records, Danger Tag Log, and Increased Surveillance Lo Tha team monitored operator performance, control room decorum, awareness of plant status, response to alarms, and use of procedure The team conducted interviews or plant tours with the Operations Superintendent, System Engineers, and operators. The team also reviewed engineering evaluations, training, and maintenance as related to questions that arose from observations in the plant.

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' Cold Leg Accumulators When the team first entered the control room at about- 9:00 a.m. ,

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on April 11, Unit I was at 100%, power and .was in two TS LCO action statements for cold leg accumulator A:

(1) Boron concentration was below the required range, a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months action statement, and

- (2) Level was below the required range, a one hour action statemen The operators were in the process of partially draining the "A" cold leg accumulator and then refilling it from the FWST to restore-boron concentration to the required range. They were performing the evolution for the second time that day. The first drain' and fill evolution had been initiated in response to boron concentration decreasing to 1918 ppm, just above the minimum TS requirement 'of 1900 ppm. After the first drain and. fill, sampling had. indicated that boron concentration in the "A" accumulator had decreased to 1848 ppm. This reduction in boron had occurred in spite of the fact that refilling was done from the FWST, which contained a boron concentra-tion of 2026 ppm. The team asked the operators to explain why th . boron ' concentration went down after the first drain and fill. They

- had a theory based.on stratification in the accumulator, coupled with inleakage from the RCS through or bypassing the check valves and entering the bottom of the accumulator, then the draining from the bottom followed by filling near the top, and finally sampling from the bottom. The operators were able to use system piping diagrams

- to show this theory to the team and .to demonstrate a good level of knowledge of the . systems. They were also able to explain why they believed the 1918,1848, and 2026 ppm' ample results were reliable number The licensee had entered the accumulator "A" level TS action state-ment at 7:08 AM. This action statement required that level be restored to the specified range within one hour or be in hot standby within the next six hours and in hot shutdown within the following six hours. The team asked the operators about their plans for restoring level to within the TS specified range, and how they were complying with the requirement to be in hot standby withii, the next six hours. The operators stated that they planned to have level restored by about 10:00 AM, which would leave them about four hours in which to shut down the unit to hot standby in the unlikely event that unforeseen problems prevented the restoration of level. They stated that a normal shutdown to hot standby would take about three to four hours. The operators understood that the intention of the action statement was not to allow seven hours to restore level, but instead to require a shutdown to be started in time to allow a normal shutdown to hot standby to be conducted and completed prior to the one hour plus six hour time limi .

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The team reviewed procedures that were in use for the drain and j fill evolution to increase boron concentratio Operators -were

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using OP/1/A/6200/09, Cold leg- Accumulator Operation, Change 2 .

Draining was done per Enclosure .4.5, Decreasing Accumulator. Level, l and filling was done per Enclosure 4.4, Increasing Accumulator level. The operators stated that there was no overall procedure for increasing boron concentration. The operators had given themselves about three hours to restore level, and based or, that had decided they could drain for about two and one- half hours. With the FWST boron concentration at 2026 ppm and not greatly more than the boron concentration in the accumulator, they would need to maximize the amount of liquid exchanged to effectively increase boron concentra-tion in the accumulator. A major consideration'was that a substan-tial portion of the piping used for draining was also used for filling. Thus some of the same liquid that was drained would be added back during filling. After draining for about one hour and 20 minutes, the accumulator level dropped below the indicating rang The operators then drained for an equal amount of-time, with no level indication. By using a chart showing accumulator levels, gallons in the accumulator, and level indicating range, the operators were able to estimate the total quantity that they would be draining and the quantity of liquid remaining in the accumulator. The accumulator was on line during this evolution, with its isolation valve open and power removed. The team noted that the written procedure in use did not address being out of the level indicating rang It also did not address time constraints of being in a TS action statement. The procedure' simply stated: "Open the corresponding valve to decrease level in the desired accumulator", then "When the accumulator is at the desired level, close the corresponding valve."

The team questioned whether the evolution being conducted had received appropriate management review and approval. The Operations Superintendent stated that verbal review and approval had been done, by the same management people who were authorized to give written-approval for procedure changes or new procedures. Still, the team considered that a written procedure covering the entire evolution of increasing boron concentration in an accumulator would have been more appropriate. The team considered management's use of verbal instructions to modify written safety related procedures, including draining below the level indicating range and related cautions, as an area of weaknes The team noted tha". the first step of the " Decreasing Accumulator Level" enclosure states: " Review the Limits and Precautions." Under limits and precautions, located in front of the procedure for cold leg accumulator operation, step 2.7 states: "Do not use Enclosure 4.5 (Decreasing Accumulator Level) for draining an accumulator beyond the limits of provided level instrumentation." However, this step had been lined out by hand and deleted by Change 26 to the procedure, which was dated April 10, 1989. The team reviewed Change 26 and its 10 CFR 50.59 safety evaluatio The forms were complete and the

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required preparation, review, and approval signatures were :all present, and all were' dated April 10, 1989. The safety evaluation

. stated that the purpose of the precaution that was being deleted was to prevent over pressurization of the FWST with nitrogen. It stated that further evaluation has determined _this precaution to be unneces-sary,' based on the small size of the drain line to'the FWST and the much larger size of the vents on the FWST. The team then reviewed the Justification Document for this procedure, which lists reasons, restrictions, and commitments associated with each step of the procedure. .The Justification Document stated that the reason for step 2.7 was to prevent over pressurization of the FWST with nitrogen if draining below the fill connectio It further stated that the level instrument only covers the top 13 inches of the tank, and 'the fill connection is midway up on the tank. Overall, the team identified no deficiencies with the records for Change 2 The operators restored the accumulator level to the TS required range by about 10:30 AM, and by about 11:30 sampling results showed the new boron concentration to be 1925 ppm. Overall on this day, the licensee had operated the unit in a.one hour TS action statement for a total of over six hours to gain a net increase-in boron con-

. centration of 7 ppm (from 1918 to 1925). The team judged that the licensee would need to increase boron concentration again in the i near -future,: and asked the licensee if there might not be a better l way'to do it. The team suggested checking with a " sister plant", !

McGuire. lThe licensee found that McGuire had a written procedure for increasing boron concentration in a cold leg accumulator that did not require entering any TS action statements or going below the level indicating range. The licensee then wrote their own similar procedure, and used it successfully during the second week of this i inspectio The team subsequently reviewed the results of the licensee's previous leak rate testing of the Unit I cold leg accumulator check valves, and identified no deficiencies with them. The team also looked at the current quantity of " unidentified leakage" from the reactor coolant system, and identified no problems with i All concerns relating to accumulator boron concentration discussed in the preceeding paragraphs were followed up under IFI 50-413, 414/89-09-02 during this inspection. This IFI is close Thermal Power Computer After the "A" co'd leg accumulator was restored to operable, the team noted that the unit one computer screen indicated that total power from each of the four nuclear instrument channels was about 100.5 percent. At the same time, each upper detector indicated about 104 percent and each lower detector indicated about 103

! percent. Thermal power of the unit was indicated to be about 9 percen The team asked the operators to explain what was the

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I maximum allowed power _ for.the unit and how'it was controlled. The operators stated that maximum allowed power was 3411 megawatts .

thermal, as ' stated in the operating licens They were instructed by management .to -implement this by maintaining eight hour average power at 100 percent or less, as indicated by .the thermal power compute The operators showed the team a station technical specification interpretation, which stated the eight hour average thermal power limi It also gave short term limits on being above= 100 percent thermal power, up to.a maximum of 102 percent for 15 minutes. The operators stated . that the thermal power computer continuously calculated average' power for the previous eight hours. .They use the thermal' power computer for normal steady state operation of the unit, but they were also to keep each power range NI total power reading within two percent of the current thermal power number. The computer was programmed to give an alarm whenever there was a two percent difference between the computed thermal power and a power range NI. A daily check of power range NIs versus the_ thermal powe was done, and~if this check or an alarm indicated more that a two

. percent difference, then the gain of the. NI would be adjusted in accordance with' station procedure One thermal power computer generates one thermal power number, using inputs from many secondary plant instruments. ,The . team asked the operators about the possi-bility of all NIs being adjusted in a nonconservative. direction based on a thermal power number 'that was erroneous because one of ;

its inputs had gone bad without being detected. -The operators stated that this was possible and in fact had' happened just last yea They saia the situation had been detected when an operator realized that the unit was generating substantially more megawatts than ever before. An LER had been written on this even The team reviewed the licensee's controls on the thermal power computer and its inputs with a system' engineer independent of the previous LER. As a result of this review, the licensee stated that two changes would be made to improve the controls on the thermal power computer:

(1) Periodic calibration testing of the unit 1 thermal power computer inputs will be added to the Computerized Periodic Test Program, to provide formal scheduling contro This had previously been done manually on an informal basis for Unit The Unit 2 thermal power computer inputs had been in the Computerized Periodic Test Progra (2) Out of calibration notification forms will be sent fr.om the instrumentation technicians to the performance system expert, j This is important, because the performance system expert trends l historical readings on the inputs to the thermal power compute These trends are used for one of the most important controls on the thermal power computer: prior to adjusting the gain on a

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nuclear instrument, the performance system engineer checks the values in the computer for reasonablenes This is done by comparisons with other values in the plant, and by reviewing historic'al trend Overall, the licensee's control of tF Nrmal power computer was considered to be an area of weakness. I ' tem will be followed up ur. der IFI 50-413,414/89-09-0 Nuclear Service Water Annunciator .The team reviewed all lit or disabled annunciators in the control room. of unit I with the operators, while the unit was operating at 100% power. Only eight of the annunciators were lit or disabled, out of a total of about 450. The team hdged that this was a relatively small number of lit or disabled annunciators, and that the operators were adequately knowledgeable about the conditions indicated by eac Two of the lit annunciators were actually lit continuously (disabled)

due to plant modification work in progres These two, RN Pit "A" Screen Hi D/P and RN Pit "B" Screen Hi D/P, were designed to indicate fouling of the trash screens on the suction side of the nuclear service water pumps. The team asked the operators what compensatory measures were being taken while these annunciators were disable The operators showed the team an Increased Surveillance Log book, that was used to record all increased surveillance in effec The team found this book to be well organized and an effective operator aid. However, it indicated that no increased surveillance was in effect for.the nuclear service water suction pit screen The team looked in the FSAR and found that these annunciators were described therein. They then asked for the 10 CFR 50.59 safety evaluation for disabling the annunciators. The licensee had a 50.59 evaluation, which identified three instruments that would be disabled during modification installation: the two annunciators in question and also tne control room indicator for Standby Nuclear Service Water Pond Level. The evaluation stated that operators would have to use compensatory measures to monitor the level of the SNSWP to comply with TS 3/4. The team confirmed that SNSWP level was being monitored daily by operators, as required by the T This i was done by physical inspection of a level stick in the SNSWP by an ;

auxiliary operator, who then phoned the level information to the control roo The fact that operators would not have indication of differential pressure across the screens in either pit for about 30 days was stated in the safety evaluation. But the fact that tiie RN Pit Screen Hi D/P annunciators were described in the FSAR was not specifically stated, nor was there any mention of compensatory measures to be taken while these annunciators were disable The licensee stated

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that unwritten consideration of compensatory measures had been done, )

and that they had decided that none were needed. The team identified j the lack of written consideration of compensatory measures as a weakness in the 10CFR50.59 evaluation. This -item will be followed up under IFI 50-413,414/89-09-0 i Shift Turnover and Control Room Decorum The team observed two morning shif t turnover Operators conducted both turnovers efficiently and effectivel Prior to turnover, the 1 off going shift assembled a thorough compilation of the scheduled

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surveillance sheets, technical memorandums, a special interest items list, and an inoperable equipment list. They then informed the on-coming shift about previous and planned plant activities. The interface and exchange of information occurred between each of the control room operators, the auxiliary operators, and the shift supervisor In. addition, the shift supervisor conducted a verbal briefing of all auxiliary operator During the turnover, the oncoming shift completed and signed turnover checklists, as required by Operations Procedure 2-22, Shift Turnover, Revision 24. During and following turnovers, several annunciator alarms occurred. The operators promptly acknowledged these alarms and took the appropriate corrective action Throughout the team evaluation the operators displayed a professional attitude concerning the plant equipment and their responsibilities as operator The onshift operations personnel appeared to be sufficiently rested, awake, and alert to safely perform plant manipulations. Operator control of access to the control room was goo Control room entry gates and 'at the controls area' markings were in place, and operators were aware of who was in the control room. Operators were attentive to their panels. Overall control room decorum was good. Operators maintained an orderly appearance and proper behavior in the roo The team noted that a number of persons in the control room (pri-marily maintenance or performance personnel) wore hardhats while standing over main control boards. The team discussed this practice with operators and management, who acknowledged that it is routinely allowed. They reviewed the potential hazard of a hard hat falling on a control parel and causing an uncontrolled equipment actuation, ,

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and the fact that many other plants do not allow hard hats to be worn in the control roo Plant Rounds The team accompanied auxiliary plant operators on daily auxiliary building rounds for units 1 and The operators used Daily Auxiliary Building Rounds sheets in the performance of the round They examined each area specified by the rounds sheet, ensuring that

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each parameter was within its required range. During the rounds, the unit 1 operator had to enter four contaminated pump rooms and the unit 2 operator had to enter six contaminated pump rooms for the purpose of examining equipment as required. Each of these areas required full dress in protective clothing. The process of multiple suiting and unsuiting was time consuming, and may be a deterrent to operator and management surveillance of the contaminated pump room Having the large number of contaminated rooms which require routine access for proper surveillance is considered to be an area of weak-ness. This item will be followed up under IFI 50-413,414/89-09-0 The team observed that the operators did not frisk when exiting each contaminated are Portable friskers were not located at any of the contaminated pump rooms. A few portable friskers were located throughout the auxiliary buildino, and generally one was within about 50 to 200 feet of each contaminated pump room. However, operators stated that they were not required to use these portable friskers, but instead were to complete their rounds, walking throughout much of the auxiliary building, and then use the whole body radiation monitors. The team reviewed Station Directive 3.8.3 (T.S.), Contami-nation Prevention, Control, and Decontamination Responsibilities,

' Revision 24. It states that exiting a contaminated area requires a whole body frisk: "a whole body frisk shall be performed at the first available frisker to prevent the spread of contamination." The team reviewed this with health physics supervisors, who stated that they had no problem with the observed practices of the operators, did not have a problem of inadvertent spreading of contamination, and did not intend to place more friskers in the auxiliary buildin The team also reviewed this matter with the operations superintendent, who stated that the observed practices would be continued and the station directive would be changed. Discussion of this item at the final exit with plant management resulted in a commitment from the licensee to re-review the resolution to this practice. The failure of operators to frisk when exiting contaminated areas, as required by the station directive, is identified as an example of violation 50-413/89-09-0 Areas and equipment examined during the rounds were all levels of the auxiliary building, including portions of the following systems:

containment spray, residual heat removal, high pressure injection, safety injection, component cooling, auxiliary feedwater, ventilation and air conditioning, eler u cal switchgear, spent fuel pool, diesel generators, and various valve galleries. The team found labeling to be overall very good, with the exception of doors and instrument root valve The operators exhibited a good " hands on" approach to the rounds, and initiated corrective actions for a number of mino-deficiencies that they observe They demonstrated an adequate knowledge of the equipment and existing condition Overall, operator rounds were very thorough.

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The , team found that housekeeping in general was very good. The team . .

identified two areas in which an improvement could be made: the 522'

elevation in: the auxiliary building had various-items of protective clothing on-the floor, and the 1A charging pump room contained tras Diesel Generator Batteries During plant rounds, the team observed' that the batteries for each of the- four emergency diesel generators did not appear to _ be seismically mounted. ' Cell motion restraints were' lacking. ;There

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were no separators between the cells and not all end cells were braced as required by current IEEE standards. In a seismic' event, the cells could move and' impact with each other as well as with the steel battery rack. When questioned about this, the licensee stated

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that these battery installations were seismically qualified, and that they had been seismically teste The team reviewed the battery seismic test results and identified no deficiencies with them. The batteries had demonstrated operability before and af ter being shaken at a minimum directional acceleration of 0.2 g. The testing had been done in 1984 by Southwest Research Institute in San Antonio, Texas. The FSAR states that the Safe-Shutdown .Ea'rthquake maximum ground acceleration for this site is 0.15 g. The' team confirmed that the battery cells and rack that were tested were the same as those installed in the plant. The team also found that the licensee had not committed to current IEEE standards that require cell separators and bracin The licensee stated that other people had questioned the seismic design of these battery installations, and that a modification was scheduled to be completed next year that would upgrade the diesel batteries by adding cell separators and bracin This upgrading was being done in response to an EPRI initiative called Safe Margin Earthquake. .The SME is calculated differently than the SSE, and the licensee stated that for this site the SME had a maximum acceleration of 0.3 g as compared to the SSE at 0.15 g. A licensee SME review of the site had determined that, from a seismic standpoint, the diesel batteries were the safety equipment that was most susceptible to failur The licensee stated that, for the site to meet SME standards, basically only the diesel batteries and auxiliary feed pumps needed to be upgrade On further investigation, the team found that this EPRI initiative had begun after the NRC had found that SSE calculations for another site were inadequat A review of the design calculations that determined the SSE for this site to be 0.15 g of ground acceleration was beyond the scope of this inspection and was not done. Overall on this issue, the team evaluated the licensee's initiative toward upgrading the seismic safety margin of the units as commendabl :

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11- Fire 'and: Security Doors

While touring the: plant, -the team observed that the door. to the 1A

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diesel generator room (fire door AX-302) did not close fully or l

latch by' itself. The team closed the door, and subsequently found that procedure PT/0/A/4200/48, Periodic Inspection of Fire Barriers

and Related Structures, change 0 requires that fire . doors "shall h latch in the closed position. automatica11y' (no external force l

. applied) when released from the open position." The team promptly reported the fact. that . door AX-302' did not close automatically to ~l the fire ' door coordinator, who checked the door and declared it-inoperable that same day. The team verified that an hourly fire watch had. been initiated on the door. The team also verified that

. the door had passed its last scheduled inspecti.on. The licensee followed established procedures with respect to this fire door, and when a problem with the door was identified to them, they did take prompt' corrective actio The team'also observed two other fire doors open because they. failed to close automatically. One was the unit I control room door (fire door 501), which the team found wide open and with no personnel in sight. This door 'is not only a fire door, but also is a vital security- doo The team promptly reported the open door to the

. shift supervisor, who assisted in closing it. ,This door, which is very heavy, had rubbed on the floor and jammed open. The team waited for a security guard, who arrived within two minute The licensee. stated that a modification was planned to install a lighter doo The control room security door problem has been referred to NRC security personnel for followu .The team subsequently observed the fire door to the IAE engineers'

office area wedged open with its doorknob, which had apparently fallen of IAE. personnel were notified, and they closed the doo As a result of finding three fire or . security doors open during

'the inspection, the team concluded that the licensee's control of doors is an area of weakness. This item will be followed up under IFI 50-413, 414/89-09-0 Outside Rounds The team accompanied an auxiliary operator on the daily outside rounds, which covered both units. The operator examined each area and component as specified by the Daily Outside Rounds Sheet. I the nuclear service water pump house, housekeeping needed improve- i ment. Various loose items were in that area, including a seven foot length of three inch pipe, a ladder, a fire extinguisher, a chair, and some wood. In the intake and pump area for the conventional low pressure service water pumps, the operator identified a deficiency (water inside a pump flow gauge) which he properly documented via the discrepancy reporting system. In addition, he initiated a work

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request and hung an orange tag as required by plant work request i

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procedure The cooling towers and their fan control rooms were inspected, where the operator replaced a few burned out light bulb The electrical switchyard was toured, with' no ' discrepancies note Overall, the team considered' that the outside rounds were performed-

.iri a thorough and professional manne Configuration Control.and Independent Verification )

The team evaluated the methods utilized by.the licensee for control-

. ling the configuration of safety systems, particularly the alignment 1 of valves and breakers, to reduce the possibility of an. occurrence which could. result in or contribute to an accident. .The evaluation included a selective review of completed system alignment verifica-tion checklists; system walkdowns; a review of Station Directive 4.2.2, Independent ' Verification Requirements, revision 1 and Operations Management Procedure 1-5, Independent Verification, revision 11; and interviews of several plant operations personne The ' team also reviewed Station Directive 3.1.1, Safety Tags and Delineation Tags, revision 21. The team identified no deficiencies with.the operators' knowledge of independent verification. procedures or with the completed system alignment verification checklist The team did identify three items for potential improvement in the ;

licensee's procedures: These items will be followed up under IFI 50-413,414/89-09-0 (-1) The procedures allow both operators who are checking and verifying the position of a valve or breaker to go together, and the team observed this to be the practice of the operator Past experiences at other sites have shown that two operators - I together are not totally independent, as there is a tendency ;

for' both to make the same mistake. A more effective' practice I is for both to go separatel (2) The procedures allow both operators to use the same remote indicator to verify the position of a valv This allows iinporUnt valves, which are remotely operated from the control '

room, to be aligned for plant startup without being physically l inspected for deficiencies. The inspection of equipment for j significant material conditions should be included in a good 1 system alignment verification proces l

(3) The procedures for restoration of a system during removal of a tagout do not address alignment or independent verification of valves inside the tagout boundary, such as a valve on which l maintenance was performe Operators that were interviewed !

stated that they were trained to list such valves on the tagout l l

restoration checklist, even though this was not specified in the plant procedures.

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, . j. System Walkdowns: AC Power and Nitrogen The team conducted a partial walkdown for two safety related systems; one electrical and the other mechanical / piping. The electrical walkdown verification checked the condition and position of the power supply breakers for portions of the unit 2 4160 and 600VAC switchgear. The other walkdown checked the valves and piping which supply the nitrogen to the unit 1 passive safety injection accumulator The team accompanied an auxiliary operator while conducting the electrical walkdown verification for the unit 2 4160 and 600VAC switchgear. During the walkdown PT-2A-4350-03, Electrical Power Source Verification Checklist, change 14 was utilized for assuring proper breaker positions. The team compared the as found positions of the electreal circuit breaker with the positions shown on the checkli st. No deficiencies were identifie While conducting the walkdown for portions of the nitrogen system for unit 1 passive safety injection accumulators, the team refer-enced site drawings CN-1562-1.1, Safety Injection NI, revision 6; CN-1602-1.0, nitrogen system, revision 13; the control room completed copy of OP-1A-6200-09, Accumulator Valve Checklist Enclosure 4.2, retype 6; and the applicable Independent Verification Checklist Enclosure 4.2. , retype The walkdown verified valve positions as compared to the above referenced valve checklist Each valve was found to have attached valve identification tags which clearly identified the appropriate valve numbe All pipe caps were installed as shown on site drawing The team did not identify any unsatisfactory conditions while conducting these walkdown k. System Walkdown: Component Cooling Water The team also performed a partial walkdown of the unit 1 component cooling water system with the assistance of the system enginee The system operating procedure OP/1/A/6400/05, Component Cooling Water, change 45, and system flow diagrams CN-1573-1.0, Rev. 16 and CN-1573-1,1, rev. 11, were utilized by the team during the walkdow The majority of the walkdown was conducted in the Auxiliary Building on levels 560' and 577' . The team traced out various portions of the system checking for proper labeling of components, material condition of the system, proper labeling of components compared to procedural requirements, and the status of locked valve The team observed system valve and component labeling to be goo All valves and components examined were labeled with large black tags with white letters that were readily readable from a distance and allowed for easy identification of equipmen The team con-sidered the overall material condition to be adequate. The only

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discrepancies noted were a few slightly leaking valves which had been previously identified by the license These valves were tagged with the licensee's orange deficiency ID tags' and had cable funnels installed beneath the The team verified that all valves observed during the walkdown were j in the correct position as required by the operating procedure, t However, valve 1KC-9, the component cooling pump 1A2 discharge valve, was found open in lieu of locked open as required by the system operating procedure and system flow diagram. The valve was

.not locked open due to the chained handwheel being separated from the valve stem. The licensee has been previously issued notices of violation for failure to lock other valves: Violation 414/86-18-01 dated June 3, 1986 and Violation 413/87-30-03 dated October 14, 198 This valve not being locked as required is identified as an example g of Violation 50-413/89-09-0 After the licensee had re-attached the 1KC-9 handwheel, the team checked all of the unit 1 and 2 component cooling pump suction and discharge valves. During this walkdown, the team noted that the handwheels on unit I valves IKC-4,1KC-9, IKC-7 and 1KC-10 were not fully seated on the valve stem The team also found that all of the unit 2 pump suction and discharge valve handwheels were more positively attached with a stem bolt and washer, while none of the unit I valve handwheels were attached in this manner. This may have contributed to the valve problem note (These valves are IKC-4, IKC-6, 1KC-7, 1KC-9, 1KC-10, 1KC-12, 1KC-13, AND 1KC-15). The final item identified by the team during the walkdown was that the valve positions of valves IKC-16 and 1KC-17 could not be determined without the use of an extension mirror due to the close proximity of the valves to a wall . The team did not note any such implement in the area of the valve . Auxiliary Feedwater Surveillance On April 12, the team observed the performance of portions of the 1B Auxiliary Feed (CA) Pump Surveillance in accordance with procedure PT/1/A/4250/06, Enclosure 13.4, CA Pump Head and Valve Verification, change 28. The team accompanied a licensed operator and auxiliary plant operator for the local performance of the surveillance. The purpose of the surveillance was to ensure that the auxiliary feed-l water pump head and flow were within the technical specification

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allowable limit During the accomplishment of the test, the opera-l tors followed the written instructions specified in the procedur At the completion of each step requiring a sign-off, work was stopped and the operators made the required signature The operators kept -

control room personnel well aware of the status of the test and informed them of any problems as they were encountere ,

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15-1 The- results of7 the surveillance (as observed by the. team)' were unsatisfactor The requirement that the . pump achieve - an dynamic head ~ pressure -(DHP) (DHP = pump discharge . pressureminus pump

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- suction. pressure) of.1521 psig was not' satisfied. . Calculations revealed.the result'to be approximately 1507 psig. At this time, the licensee had already entered a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months T.S. - Action . Statement due to removal of, the pump from service for t? stin The following day, the team inquired about the operability status of the' 18 auxiliary feedwater pump. The team was informed that the pump-had passed its operability run and had subsequently been declared ~

. operable by-the licensee. The team reviewed the surveillance records'.

This data was accompanied by a Duke Power Company, Procedure Discrepancies-Process Record (DPCPDPR) which recognized the discrepancy'. The problem resolution as'specified on the DPCPDPR and an accompanying calculation on enclosure 13.4' of procedure PT/1/A/4250/13B was to ' compensate for'-

-the temperature difference in the suction source for the pump (the UST).

The UST temperature had been found to be approximately 140 degrees F, which was higher.than the tank's normal temperature of 90 degrees Additionally,. .the licensee had determined . that the temperature difference in the UST had been caused by failure of a steam regulator in' the steam supply for the tank. This regulator was subsequently

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repaired /r9placed by the license On May 1, the team observed the performance of the 1A auxiliary feed-water pump surveillance in accordance with procedure PT/1/A/4250/06, Enclosure'13.3, CA Pump Head and Valve Verification, change 29. The team observed the local performance of the test by .two auxiliary-operators. -The test was performed as specified by the procedure,- i and'the results were satisfactor m.' Test Observation The team observed performance of the INS-1B pump performance test, PT/1/A/4200/04C, Change 0 to 27 incorporated, dated 4/30/86. Review of the procedure and observation of the PT resulted in the followin comments (Note: The pump satisfactorily past the performance PT): { Section 2.0, References, should include the KF drawing showing the location of 1KF101B, which is listed on Enclosure 13.5, Valve Checklis . Step 6.8 refers to minimum and maximum flows for pump operatio !

Step 12.8 and step 12.10 start the pump and throttle flow. No j cautions or warnings are included immediately prior to these steps to reinforce the limits of pump operation. During the performance of the PT, the pump was run below the minimum flow i

value until the throttle valve could be properly adjusted.

I Starting the pump with the throttie valve set to allow minimum

flow could possibly eliminate this problem.

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16 The required values in the procedure have many times the accuracy indicated in their significant figures than can be obtained through the measurement instrumentation use For example, step 12.10 states, ".. . obtain a flow of 620.3 gpm (613.8 to 626.7 gpm) by observing INSPG5120. . ." . The flow instrument is a 0 to 700 gpm Barton with 10 gpm division Readings are possible to the nearest 5 gpm, if the needle is stable. The instrumentation used in the test were subject tc considerable bounc . Communications between the remote location of the throttle valve and the meter that reads the flow was difficult during performance of the P One person reading the flow gauge walked about 40 feet to a location that could be seen by another technician in a doorwa This person then walked to a position that could be seen by the operator manipulating the throttle valve. The operator changed the valve position, and the process started again, until the proper flow was indicate Improved communications should be worked ou . In the pump room, instrument number 1NSTH5010 was broken, and its laminate tag was wrong. In addition, the motor covers on NS pump 1B were loose or missin These deficiencies will be followed up under IFI 50-413,414/89-09-0 Safety Tags The site has two procedures which focus on the control and issuance of safety and delineation tag These procedures are Station Directive 3.1.1 (0P), Safety Tags and Delineation Tags, revision 21; and Operations Management Procedures 2-1, Audit Of Safety Tags and Tagout (R&R)'s, revision 11. The first of these two provides for the issue, placement, recall, transfer, and removal of red personnel safety tags, white equipment safety tags, and yellow " HOLD" safety tags. The audit procedure is implemented vigorously by operations management personnel to make sure that none of the listed tags are missing or inappropriately applie The team selected several safety tags which were fastened to the unit 2 4160 VAC switchgear. The tags were checked against the l appropriate tagout (R&R) record sheets and were found to be active and properly indexed. The tags and the tagout records were com-pleted, signed, dated, and applied as required by the controlling station directive. The tagout (R&R) records sheets which have been outstanding for an extended period were evaluate Two of the sheets, one for each plant, indicate that in 1987 the diesel generator engine fuel oil booster pumps had tags applied to their power supply switches. The plant operations supervisor stated that 3

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L 17 these tags are necessary due to the incomplete status of the instal-lation of these booster pumps. He further revealed that prior to installing these pumps more guidance must be provided . by design engineerin A Unit I tagout sheet indicated that several condensate flow orifice bypass valves have had tags applied to them since 1986. The opera- ,

tors stated that this is an acceptable site practice authori.ed i by the condensate system controlling procedure. The procedure allows the tags to be temporarily lifted as required to manipulate the valves. Upon completion of the valve operation the valves are returned to the properly tagged position and then the tags are reapplie A similar tagout sheet has remained outstanding since 1984 for two alternate power supply breakers in unit These two breaker 3 are normally " RED" tagged in the off position. But when the need arises the breakers could be put into service and operated, as allowed by i procedure. Upon completion of use, the breakers would be returned to the tagged positions and the " RED" tags would be reapplie The team found that there are a limited number of other instances similar to the above. Allowing certain tagouts to remain active for extended periods and allowing the tags to be temporarily lifted has been authorized by site procedure The team considered that leaving red tags in place for years and routine temporary lifting of red tags potentially dilute the importance of the red tag syste o. Operator Access The auxiliary operators are issued key rings which contain all of the required keys for routine access to areas which are administra-tively controlled. In the event that the normal security door locks improperly function, provisions have been made which will allow these doors to be opened by the operators. Keys for other personnel who may need them for access to administrative 1y controlled areas may be obtained from the shift foreman. The team observed operations personnel using the system and when questioned each of those interviewed were familiar with the key control process and its importance. The system utilized for key controls seems to be working satisfactorily, p. Required Reading The shift foreman's administrative staff is responsible for assuring that the various plant operators complete their required readin The required reading material may consist of procedures which have been recently revised and other material which management feels that the operators should be familiar wit The tehm verified that the operators have been reading the required material and that they are '

familiar with what they rea The administrative staff requires

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that each of the operators complete reading the material within the established time perio Upon completion, the operators sign or initial the required reading notebook as proof that they reviewed the material, Overtime The team verified that the licansee has in place controls and .

procedures for use of overtim Station Directive 3.3.0 (SS),

Control of Overtime Hours, revision 2 provides guidance to help assure that the licensee maintains the staff overtime and work hours within the limits of T.S. Section 6.2.2,f. The team evaluated the overtime hours which were worked by the plant operators for the months of January, Februa ry , and March 198 The team concluded that the operations staff does frequently work overtime hour However, after evaluating the records and interviewing several operations personnel, the team concluded that overtime hours are being worked within limits of the T The team also observed operators dividing up available overtime days i among themselve They were adhering to a plant administrative limit of 60 work hours in any 7 consecutive days. This 60 hour6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months limit is substantially below the TS limit of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months in 7 day i The operators stated that these administrative overtime limits are in force during outages as well as when a unit is operatin Scaffolding Controls While walking through the plant, the team observed scaffolding that was not tied down and had no kickboards. For example, scaffolding in the 1A diesel generator room had a work platform that was approximately six feet above the floor and had no kickboard In addition, this scaffolding was not tied down to prevent movemen The team subsequently reviewed scaffolding controls with the licensee. The licensee statad that the scaffolding control program was recognized to be weak, and that an improvement effort was under- ;

way. Personnel safety items such as tiedowns and kickboards were to

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The team inquired about scaffolding controls as related to potential impact on operability of safety equipment. Three specific concerns were discussed: additional loads placed on safety equipment, physical interference with safety equipment, and seismic considera- 4 tions. The licensee has a program in place for evaluation of placing additional loads (such as scaffolding) onto safety piping. This program is implemented by Station Directive 3.8.17, Installation of Temporary Loads, revision 4. The licensee also tas procedures that address physical interference with safety equipment (ie. by obstruct-ing a travelling valve stem): Station Directive 3.8.12 and also Station Directive 2.11.6, General Scaffold Guidelines, revision In addition, the licensee stated that the crews of scaffolding

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19 l builders are aware of equipment operability concerns and have demon-strated the knowledge needed to be able to build scaffolds without affecting the operation of equipmen The potential seismic impact of scaffolding on the operability of safety ' equipment was not addressed in the licensee's procedures.

l Since the scaffolding is not seismically qualified, the concern here is that scaffolding erected over or near safety equipment could, in a seismic event, reduce the functioning of the safety equipmen This concern is addressed in NRC Regulatory Guide 1.29, to which the licensee has committed. The failure of the licensee's procedures to address seismic impact of scaffolding on operability of safety equipment is considered to be a weakness. This item will be followed up under IFI 50-413,414/89-09-0 DC Electrical Ground Faults In the control room, the team observed a unit 2 lit annunciator,

"125 V ESS PWR Channel A Trouble", that indicated an existing vital de system electrical ground fault. The licensee was aware of the ground fault and had recently initiated an MWR to locate and repair i The team then discussed vital de ground faults in general with licensed operators, cognizant I&E engineers, and the cognizant I&E foreman, Discussions covered safety significance, IEN 88-86, frequency and duration of ground fault occurrences, policy and procedures, methods of detecting and locating, annunciator setpoint and calibration, types and sensitivity of ground locating equipment, and IEN 88-86 Supplement 1. The licensee had procedures in place to identify and correct ground fault However the procedures and practices did not include the use of any portable ground locating equipment, such as is used by other plants, including the licensee's sister plant, McGuire. The use of this equipment would enable ground faults to be located and isolated much more expeditiously. The licensee stated that vital dc ground faults are likely to take a week or more to locate, due to waiting for operations to open breakers. Use of portable equipment would not require opening breakers and would enable ground faults to be located and repaired within one or two day The team considered the use of portable de ground fault locating equipment as a much needed improvement, with direct safety importanc This item will be followed up under IFI 50-413,414/89-09-1 Safety Rtview Group The team observed a meeting of the Safety Review Group. The subject of the meeting was a review of draft LER 413/89-011, titled "Techni-cal Specification Viciation for Lower Containment Compensatory Action Not Being Performed due to Failure to Notify Appropriate Personnel".

This event centers around a large number of :ontainment fire detector failin In two samples, 37% and 50% were found to be out of cali-bration. Design Engineering had sent a letter to Compliance stating

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th'at both- unit 1 and unit 2 lower containment fire detectors should ,

be considered inoperable; _ Compliance-then sent a Technical Specifi-cation Operability Notification Sheet to unit. 2 operators. but not unit 1. As a result, unit 2 operators conducted the 'TS required hourly temperature monitoring in lower -' containment but: unit 1 operators did not. ' The failure of . Compliance to notify unit l'

operators 'was identified and discussed' as the only root. cause of this even .The failed : detectors were Hochiki model SIF-24F. Ionization Smoke Detectors, which .had been installed throughout the Containment Buildings. Turbine Building, Auxiliary Building, and. Service-F Building in 198 'l In' January 1989, a high failure rate of the detectors located _in the Containment Buildings was recognize In February 1989, Hochiki Electroni.cs determined the.cause of the failures to be a high level of radiation. The licensee plans to replace the Hochiki ionizatio detectors in the containments with more reliable photoe'lectric type

~ detectors, as recommended by the manufacture The team observed the discussion- among the Safety Review Group members to. be lively, open, and focused on the details and wording of. the LER. However, the team noted that a significant root cause of this event had been overlooked - the purchase of the. Hochiki detectors for use in containmen Had the purchase order correctly specified the environmental conditions ' (including radiation) in

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which these detectors were to be operated? Are incorrect purchase order: specifications for safety. equipment a recurring problem?. Th team considered that the identification of all contributory causes i of. a event and accomplishment _ of complete corrective actions to prevent recurrence are the most safety significant parts of an LE The Safety Review Group stated that they would investigate the purchasing of these detector The team reviewed approximately- two hundred licensee LERs, and found .

them generally to be well written and complet Only one other case of overlooking a major root cause and corrective action was identified. The team judged that this instance of incomplete identi-fication of root cause and needed corrective action was an isolated case.

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In the area of Operations, . one violation (paragraph. 2.k) and no devia-tions were identifie . Emergency Operating Procedures (42700, 2515/92) E0P/GTG Comparison The team reviewed the relationship between the Catawba E0Ps and the plant specific technical guidelines (PSTG). The Catawba PSTG was l I f

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developed from Revision 1 of'the ERG by the safety analysis group at the Duke' Power general office. The PSTG incorporates a number of additions to, deletions from, and restructuring of the ERG resulting from:

plant-specific design differences preference for some elements of ERG Revision 0 engineering evaluations operating philosophy operating experience experience with other vendor guidelines verification and validation activities Those changes determined by the safety analysis group to be safety significant were justified in two deviation documents, dated June and July 1984 In addition, plant specific setpoints were developed by the safety analysis group for use in converting the ERG into the Catawba PST However, the document, " Emergency Procedure Guideline Setpoints," was not approved until May 198 Duke Power identified one incorrect setpoint, pressurizer level, in the original revision of the Catawba E0Ps, and the E0Ps were subsequently correcte Production of the upgraded Catawba E0Ps from the PSTG was conducted by the document development group of the Catawba operations section in parallel with PS1G development. E0Ps were produced by application of the principles in the Catawba writer's guide to the technical information in the PSTG. Following completion of the E0Ps in January 1984, verification and validation of the procedures began, with implementation of the procedures on Unit 1 in May 198 A description of the PSTG was submitted for NRC approval as part of the PGP in February 198 Upon the request of the NRC, the deviations document was provided for revie Subsequently, the NRC required that the deviations document be revised to be based upon Revision 0 of the ER In this version, some deviations were included by Duke Power due to preference for the Revision 1 ERG approach. Several requests for additional information were made by the NR In SER Supplement 6, dated May 1986, the NRC concluded that all information received on the PSTG was complete and adequate at that tim The team con. pared the Catawba E0Ps to the ERG to verify that the L accident mitigation sequence of the ERG was represented in the E0P The E0Ps were determined to adequately cover the broad range of accidents and equipment failures addressed in the ER The role of Duke QA in the development of the PSTG and upgraded E0Ps was reviewed. There was no documented QA involvement in the development of the Catawba PSTG. The QA departacnt at Duke General Office reports performing an overview of the McGuire PSTG, which was reported to be a similar process, but has no record of any direct I

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n involvement in the? Catawba PSTG - development. ' However,. the team found that adequate management controls ~ (general office safety analysis group oversight, Catawba- document development group) had been applied in' lieu of QA involvemen The ' team compared ' the E0Ps to the Catawba PSTG .and found many, p differences, where there should be none. These differences are L 11dentified by the designation "PSTG DEV" in apper. dix B. The. team did not - consider the numerous instances of a single PSTG step which -

had been broken out to multiple steps ir the E0P. as constituting - ,

' di f ferc.nce s . An assessment of this comparison will be performed during a future inspection under IFI- 50-413,414/89-09-1 The' current: Catawba writer's guide applies to both E0Ps and A0P Review = of the E0Ps. against- the requirements of the writer's guide identified a variety of deviation The_. most significant and

. consistent .of these ' is the . improper structure. and applic3.an of cautions and notes (paragraph 3.b). This weakness 1 suggests a lack of verification against the writer's. guid '.The relationship . of procedure nomenclature to the control roo . labeling was found'to be clear-and consisten The.AOPs contained many.more deviations from the writer's guide than-did the E0Ps.- Every aspect of the A0Ps contained examples of lack of conformance to guidance, as well as, inconsistencies within and between the AUPs.. The Catawba staff stated that the- A0Ps had neither been rewritten nor verified to correspond to' the writer's guide and

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-that the schedule for upgrading the AOPs has been receatedly~ delayed due'to reprioritization. The team finds this delay undesirabl Independent technical adequacy review of the E0Ps The team. reviewed the procedures listed in Appendix A and found that generally the vendor recommended accident mitigation strategy was followed. However, the team identified many instances where the vendor recommended action sequence was not followed. Although some of these action sequence variations were cited in the deviation document, many of these variations were not - documented. Another variation from the vendor guidance was the lack of entry conditions contained in the E0Ps. The two entry pointy were E-0 and ECA These procedures listed symptoms which would require implementation of the procedures but did not have definitive entry conditions as in the ERG and the PSTG. Some of these variations are identified in appendix B and will be resolved under IFI 50-413,414/89-09-1 Cautions and notes were consistently incorrect in application of the writers guide. In'some cases cautions were actually notes or action '

steps required in the step sequenc Notes were at times actually cautions or procedure steps. Some notes and cautions that were !

appropriately . labeled as such lacked conformance to the writer's J l

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guid For example, cautions were generally found lacking identifi-cation of the potential hazard to equipment or personnel as required by t'e writer's _ guide, and both notes and cautions were written containing action steps -or conditional steps also contrary to the writer's guid Specific examples are delineated in Appendix Peacekeeping deficiencies were identified during the simulator inspection. of the E0Ps and are discussed in paragraph No deficiencies in the control room usage of peacekeeping aids were identifie The degree of adherence to the guidance in the ERG was found to be generally acceptable although, as documented in Appendix B, many undocumented deviations existe Operator action setpoint values were contained in the Catawba set-point document and associated engineering calculation sheets. These values were used in the E0Ps except for the few instances noted in the appendice Control room drawings were inspected to verify that E0P specified components were accurately typifie The team found that the safety significant deviations identified by the licensee had been reported to the NRC. Safety Evaluations for these deviations were not inspecte c. Review of the E0Ps by inplant and Control Room walkthroughs Inplant and Control Room walkthroughs of the emergency and abnormal procedures listed in appendix A were conducte Generally, the nomenclature appeared to be consistent between the procedures and the instrumentation and labeling on the control board. The discrep-ancies noted were enumerated in appendix D. The licensee committed to review these and make changes as appropriate. Resolution of this issue is identified as IFI 50-413,414/89-09-1 Indications, annunciators and controls referenced in the E0Ps were found to be available to the operators. One set of emergency and abnormal procedures was maintained in the Control Room at all times for each unit. These procedures were verified to be the latest revision. A discrepancy between step C.4, RNO, of procedure EP/1/A/5000/01, Reactor Trip of Safety Injection and the S/G pressure meter in the Control Room was found during the walkthroug This 1 item had previously been identified co the licensee in August 1987 :

l but had not been resolved. Resolution of this issue wil' be identi-L fied as IFI 50-413,414/89-09-14.

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While the: results of the walkthroughs were generally' positive, some discrepancies ; in the' areas of technical adequacy, writer's guide,-

adherence and human factors were noted. Technical and human factors discrepancies are noted in appendix B while. writer's guide discrep-ancies 'are noted in appendix C. .The licensee has committed' to consider 'the. discrepanc-les identified in the -aforementioned

,: appendices. Appendix C discrepancies will' be' identified as' IFI-50-413,414/89-09-1 <

Operators' stated that the level of noise in the Control Room caused -

by auto-start .'of both.. ventilation trains during S/I response ~ is

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cxcessive and requires shouting _ for audible communications between personnel. Problem Investigation Report serial number;0-C-89-0145 dated April 12,. 1989, had been' submitted to Duke Power design-engineering L for evaluation and correction. The design engineering staff reported that a sound survey during use of both trains of

' control room ventilation _ is currently being scheduled and that necessary action:will be based on analysis of sound survey finding This item will be' identified as IFI' 50-413,414/89-09-1 Due to time constraints, many of the aspects of thE validation and verification program that were applied to the development of the E0Ps were not inspected in' depth. Deficiencies in ' connection with the licensee's ongoing evaluation of the E0Ps are identified in paragraph Simulator Observations The -team observed a crew performing the following five scenarios on-

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the Catawba simulator:

(1) Steamline break outside containment (2) Loss of all ac power (3) S/G tube leak (4) S/G tube rupture with a steam line brea (5) Natural circulation cooldown with a void in the reactor head The procedures provided operators with sufficient guidance to fulfill their responsibilities and . required actions during the emergencies, both individually and as a tea The procedt.res did not cause the operators to physically interfere with each other while performing the E0Ps and AOPs. However, the concurrent use of several AOPs resulted in operators responding to

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, the directions of more than one person at a tim The procedures did not duplicate operator actions unless required (e.g. , for independent verification).

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When a transition from one E0P to another E0P or other procedure was required, precautions were taken to ensure that all necessary steps, prerequisites, initial conditions, etc. were me However, the method of filing procedures made it possible for an operator to select the wrong procedure from the filing cabinet in the simulator

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Control Room. Operators were found to be knowledgeable about where to enter and exit the procedures.

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It was observed that the entry symptoms contained in the E0Ps were not sufficiently clear to preclude an operator from inadvertent implementation of certain procedures. An inconsistency between the plant and simulator existed in that peacekeeping used in the plant for E0Ps and required by the PSTG was not used in the simulato Deficiencies in 1) concurrent use of several AOPs, 2) procedure filing and 3) clarity of entry conditions will be identified as IFI 50-413,414/89-09-1 Activities that should occur outside the control room were initiated by the operators and proper confirmation of their completion was given. These actions were inspected during in plant walkthroughs of the procedures. However, one deficiency was noted in that the simulator was unable to simulate the local closing of NV-295 on malfunction of NV-29 This deficiency prevented the proper completion of the planned scenari The team reviewed audit cccumentation and conducted interviews to determine the quality assurance measures taken to assure that the emergency procedures were adequate and that they met the require-ments of the Procedure Generation Package (PGP). The team found that the QA organization conducts audits at periodic interval The adequacy of these audits was not examined in detai The team verified that the PSTG and the set point document are controlled documents. Station master files, retain E0P retypes and V & V associated with the E0P E0P user interviews The team conducted interviews with six licensed operator The operators felt that the E0Ps had been improved with the recent revi-sion. Those interviewed expressed their belief that the level of detail.in the E0Ps was adequate for and compatible with the level of knowledge of the typical operator. Overall, the operators had confi-dence in the ability of the E0Ps to perform their intended functio The operators noted that the A0Ps are not at the same useability level as the E0Ps. Those interviewed felt that an upgrade to the AOPs similar to that which the E0Ps received would be beneficia In the area of Emergency Operating Procedures there were no violations or deviations noted.

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-4. Support of Plant Operations (62700,42700,37700) Maintenance interviews Interviews were conducted with mechanics, IAE technicians, . and maintenance supervisors and manager The interviews concentrated on maintenance training and retraining, overtime, supervision, operations / maintenance interface, and staffing. Some strengths and weaknesses were identified during these interviews and are discussed belo Interviews with four mechanics and four IAE ' technicians indicated that there is a good working relationship between the various plant work groups (i.e. operations, maintenance, health physics, and engineering). All who were interviewed conveyed a " team effort" attitude. All felt that they worked together well to operate and-maintain the plan This attitude was determined by the team to be a strength and overall performance should improve as the groups continue to work togethe The mechanics and technicians stated that they feel that plant management has taken measures to emphasize procedural compliance and independent verificatio Maintenance personnel were provided training sessions on these topics, and discussions are periodically conducted at the daily crew meeting During an interview with an IAE supervisor, an incident was used to demonstrate management's commitment to ensure compliance with the independent verification progra In this incident, two technicians were found to have violated the independent verification program and were given written reprimands that were placed in their personnel file This action by management impressed upon plant personne) ,

that management was serious about compliance with the independent '

verification program, as well as, procedural compliance. This was seen by the team as a strengt '

Discussions with the mechanics and technicians revealed differing attitudes with regard to overtime. Management has taken steps to reduce the amount of overtime for plant personnel as a result' of discussions with the NRC Resident Inspector. Prior to taking action to reduce the emount of overtime, there were instances of personnel exceeding the T.S. limits on overtime. As a result of management's actions, some of the mechanics and technicians enjoy the reduction in overtime, while others feel there is not enoug The first line ,

i supervisors expressed the feeling that they had sufficient staffing to handle the day to day maintenance requirements, but that increased staffing would be needed for outages in order to comply with the requirements on overtime and to perform the outage work on schedul !

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The mechanics and technicians expressed. dissatisfaction with the manner in which the training and . qualification program (ETQS) was being implemented. They did state that they felt that the objective j of the program was good and that once the bugs get worked out, it will be beneficial. They stated that they . did, not ' feel- that the

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time requirements for completing. the program were fair This was because .they felt that certain requirements could not be - met in a

. two year period. Additionally, they expressed. concern that they may lose positional status or promotional opportunity if they did not ,

meet the time restraint Discussions with the supervisors of these men indicated that the mechanics and technicians did not fully understand the program '4 and its requirements. Some of the concern expressed by them was-unjustified, according to the supervisor The supervisors stated -

that some of concerns were due to the program changing several-

, times in order to improve it. Other concerns were due to the plant personnel. responding to the personnel that were brought in from'CM When the CMD personnel were informed of the program they apparently-misunderstood how the program was to work. The CMD personnel then discussed. their understanding of the program with the. permanent pl. ant personnel and the problem grew. The. supervisors stated that had management communicated the intents and requirements of the program better, there would not have been- as much adversity. The supervisors also stated that no one would lose positional status or promotional opportunity by not . completing the program within the requirnd time fram They said that this was another case of misunderstanding what was promulgated by managemen Discussions with the Maintenance Manager indicated that the licensee was already aware of the problem and was taking steps to correct i The-weakness was in the Employee Training and Qualification System (ETQS) and was due, according to the Maintenance . Manager, to the program being in a state of flux as a result of reevaluation of the system. Management is attempting to improve the system by making the requirements for completing the tasks more consistent and relative to job performance. Additionally, management is evaluating

'the time requirements for completing the qualification program and how to deal with those that are delinquent in their qualification The ETQS for IAE is scheduled to be implemented by June, 1989, while that for mechanical W ntenance is scheduled for January, 199 There is a possibility that the implementation of the IAE system wi? ' be delayed to January,1990, but no decision had been reached at the time of the inspectio Every mechanic and technician expressed a feeling that their first line supervisor was the best possible. All were supportive of the first line supervisors, but expressed some dissatisfaction with upper management. This dissatisfaction was concentrated in two main

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area One was the ETQS discussed above, and the other was the change of ' shift assignments and shift schedule for: the current outag The IAE ' technicians stated that they were dissatisfied with manage-ment's- decision to alter the shift schedule and assignments. The supervisors of these technicians stated that it'was only a perception that the technicians would lose some overtime. _ The supervisors also stated that- the problem could have been avoided if there had been better communications among those involved in making the decisions and those that the decisions affecte The first 'lin'e supervisors, in general, felt that their supervision was supportive, but felt that first line supervisors were not .

included enough in some decision making processes. They felt .that if they were included more, they could help correct problems .that arose due to misunderstanding the intent of what was to be _imple-mented. This feeling apparently was also due to poor communications

. because their supervisor, when interviewed, stated that 'the firs line supervisors were included in the process but may rot be aware-of i The interviews 1 indicated that upper management may not have a working l' . feedback loop .in the communication path to ensure that the: communi-

cated ' idea was received and understood properly. Discussions with

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the Mechanical and IAE Supervisors and the Maintenance Manager identified this as a ' potential proble They agreed that the communication path may have a missing link and that.it was a weakness that would be investigated and resolve Following are the strengths identified during. the interviews and observations. There is an attitude of being on the same team and everyone working together to achieve a common . goal . Management

. tries to take an active role in the daily operation of the plan Management .is serious' about enforcing procedural compliance and independent verificatio And, lastly, management is trying to improve the qualification program for mechanics and technician Only two weaknesses were identified during the interviews and observations. These were the present state of the qualification program, and the problems with communications. These issues will be

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followed up under IFI 50-413,414/89-09-1 Nuclear Station Modifications As of April 11, 1989, there were 141 active NSMs for the Catawba project. Of these,17 safety related . isms were " Design Complete -

Not Ready to Work", and 34 safety related NSMs were " Design Complete

- Not Installed", for a total of 51. active safety related NSMs. The team reviewed two NSMs for compliance with the requirements of the Nuclear Station Modification Manual (NSMM) and Catawba Nuclear

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Station Directive (CNSD). The NSMs were: NSM #CN-11042, Rev. O, Replace Valves IKC50A and 1KC53B with 20" Possiseal Valves; and, NSM

CN-11159, Rev. O, Replace Reactor Vessel Nonle Inspection Hatch

' Cover Engi.neering Safety Evaluations for the NSM were thorough, addressing the potential affect on the FSAR and Technical Specifications as well as unreviewed safety questions. . The NSMs contained the -

neces sary . documentation and were normally completed . as required by the procedures. There was one example, NSM #CN-11159, which was completed on November 29, 1988, and the -affected procedure, MP/1/A/750/42 had not been revised as of April 28, 1989. This is considered to be an isolated case and the team concluded -that the NSM program was satisfactor Temporary Station Modifications (TSMs)

As of April 11, 1989, there were 131 active TSMs, of which 33 were

. safety relate Of the 131 active TSMs, 68 were older than 16 months, with 7 being safety relate CNSD 4.4.5, Rev. O, Temporary Station Modifications, dated July 5, 1988, states that temporary modifications should not be installed for more than 12 months for those not requiring -an outage, or. the next refueling outage for those that do require an outage for remova The licensee stated that the intent was to apply the directive to all new TSMsj and-to work at reducing the number of existing TSMs. A meeting was scheduled for May 24, 1989, to discuss reducing the number of active NSMs and TSMs. The high number of TSMs and the duration of time some are open is considered a weakness. This issue will be followed up under IFI 50-413,414/89-09-1 Two TSMs were randcmly selected to determine the effectiveness of the control and documentation of TSMs. The modifications selected were WR# 007121, Replace SSF Diesel Water Jacket Heater Model

3P5-0600 with Model #C5033-050; and, WR# 009389, Replace VI Pressure Regulator (PR-2) with Fairchild Model 80 Both were found to be adequate and documentation was completea as per CNSD 4.4.5 and NSMM j Section Fifteen safety related TSMs were selected to review the affected control room drawings. The drawings were reviewed to verify proper reference to or red lining of the applicable TSM on the affected

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drawing. No discrepancies were noted during this check. A complete

! review of control room drawings for the effects of all types of f

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plant modifications was not conducted by the team due to issues in this area which had already ' oeen addressed by the resident inspectors. The results of their review of the area is documented by a violation in their April,1989 monthly inspection repor w__ __ - - _ - _ _ -

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d. Licensee Event Reports and Potentially Reportable Events The team examined the licensee's administrative control programs for review, investigation, and reporting of non-routine events to assure conformance with regulatory requirements and to assess its efficiency in increasing equipment reliability through correct identification of root causes and by initiating appropriate corrective actions. The program was'being applied to a number of events which were the scope of the team's evaluatio These events occurred between August 1, 1988, and April 24, 198 The number of events reported during the previous SALP period was 68. The number reported during the 9 month sample performed for this inspection was 23. The percentage of personnel errors remained constant at approximately 33%, however, the percentage of procedural deficiencies increased from approximately 3% to approximately 17%.

The reduction of total LERs indicates that the licensee is making an effort to reduce reportable event However, the increase in procedural deficiencies indicates that a review of procedures !s warranted. The licensee had realized this also and was in the process of performing the necessary reviews and procedural upgrade The area of potentially reportable events is covered by the Problem Identification Report (PIR) program. This program is governed by CNSD 2.8.1 which describes the problem identification ard assignment of the responsible group to investigate the problem. The FIR program serves as the basis for the processing, evaluating, and resolving of any identified problem. The PIR program also includes provisions for recognizing and reporting events covered by 10 CFR 50.73, as well as, 10 CFR 21 and other reporting requirement e. Preventive / Predictive Maintenance Programs The team reviewed the licensee's preventive / predictive maintenance programs in an effort to assess management initiatives to improve the availability and reliability of equipment servic The team determined that the licensee has well established maintenance program The Standing Work Request (SWR) program is used to schedule, track, and document routinely performed preventive maintenance task Daily, an SWR report is generated that contains a complete listing of all maintenance, pe.riodic testing, and scheduling records, as well as, the associated schedule date The weekly periodic test report contains the completion dates for all surveillance from the previous week and/or surveillance requirements not previously reported. An overdue report is run daily to identify any required SWR item that has reached or exceeded the earliest dat As of April 24, 1989, the team verified that there were no T.S. items overdue, and only a few backlogged PM items.

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The licensee has. a ' computerized ' program to assist .in . scheduling PM items.. The' program calculates the earliest. start date and the late date, to ensure that the requirement does not exceed any T.S. limi This' includes the 3.25 times the periodicity for three consecutive

.. times. - Any requirements that have' been missed to date' have not been the result of lack of scheduling, but due to other factors. ( personnel error, plant conditions, lack of parts).

The team discussed the predictive maintenance program with plant .

. personnel. .The goal of the program is to provide a structure for monitoring and evaluating rotating' and. reciprocating equipment' in -

order to aid.in predicting equipment failure. ~

The predictive ' maintenance program consists- of oil analysis' and vibration . analysi s . and trending. During 1988, ' performance trending was conducted on. approximately 300.. components. The licensee has a'

plan' that will expand the program wo include more high maintenance components in the vibration analysis database and to also purchate additional diagnostic . equipment. Management has provided excellent support:to this effort in order to insure its succes Information Notices (ins)

Information Notices are useful in avoiding fmaking the same mistake that others have made, as well as, providing for increased equipment-availability. The team examWed the licensee's program for review, response, and resolution of ins. A random selection of six notices issued during the previous.18 months was performed and the applicable notices were reviewe The following lists the ins selecte IN 89-08 Pump Damage Caused by Low Flow Operation, January 26, 198 IN 88-86 Operating With Multiple Grounds in Direct Current Distribution Systems, October 21, 198 IN 88-74 Potential Inadequate Performance of ECCS in PWRs During Recirculation Operation Following a LOCA, September 14, 198 IN 88-34 Nuclear Material Control and Accountability 'of l Non-fuel Special Nuclear Material at Power Reactors, May 31, 1988.

l IN 87-60 Depressurization of Reactor Coolant System in PWRs, e December 4, 198 IN 87-53 Auxiliary Feedwater Pump Trips Resulting from Low ,

Suction Pressure, October 20, 198 l

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The team verified that the Nuclear Safety Section of the Nuclear Safety Assurance Group at 'the General Office coordinates the processing of ins. 'This requires inputs from various plant sections, including Design / Technical Services Engineering Support, Production Training Services, and . Regulatory C )mpliance. Applicable ins are distributed to the appropriate station work group for information, for additional input, or for corrective action if necessar The team determined that the licensee reviewed the subject ins in a timely manner and any actions that were required were also performed in a timely manne Backlog Status of Maintenance Work Requests (MWRs)

The team reviewed the status of d- MWR backlog and the adequacy of the assignment of priorities to MWRs. The status of outstanding MWRs is published biweekly by the Integrated Scheduling Group. The MWRs are categorized based on whether the work '+ Corrective Maintenance -

Non-outage, Corrective Maintenance - Outage, Preventive Maintenance, or Modification. Although the number of MWRs outstanding appeared large, Catawba is average compared to the INPO guideline As of April 24, 1989, there were 5,332 outstanding MWRs. These can be divided-into: 1,953 Corrective Non-outage; 1,994 Outage; 504 PM; and 881 Modification. As of May 4, 1989, the Outage MWRs outstanding had been reduced to 1,646, with many of those (approximately 600)

waiting for functional testing. The ratio of Non-outage MWRs greater than 90 days to the total number of Non-outage MWRs has remained approximately constant at approximately 45%, which is better than the !

INP0 guideline of 52%. Although the raw data is not encouraging '

(proper management of over 5000 items is very difficult), team review of the details of this backlog determined that the licensee does have control ever the backlog and is actively pursuing means to reduce i The I,tegrated Scheduling Group conducts a daily review df out-standing MWRs by priority code and works with Operations and other departments to determine which MWRs could be worked in conjunction with plant availability. This was considered to be a strong point ;

by the tea I Priorities are established based on the classification of the component and the nature of the work. Priority 1, 2 and 2X are assigned to work requests of a critical nature and to safety related equipment. Priority 3 is assigned to work that will improve plant ,

performance or is for preventive maintenance. Priority 4 or 5 are '

for non-critical work with Priority 5 being used to designate outage related work. The team concluded that the licensee adequately prioritized MWR _ _ - _ _ _ _ .

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h. Work Requests The work request system was reviewed to determine work flow from origination of a work request at the time _of discovery of a problem with plant equipment, through the actual repai Maintenance Management Procedure 1.0, Revision 25, dated January 13, 1989, " Work Request Preparation", and Operations Management Procedure 2-3, Revision 2, dated March 22, 1988, " Operations Work Req. ;ts", were reviewed. Interviews were conducted with personnel from cperations, the Shift Manager, the Unit Operations Manager, the Mechanical Planners, Integrated Scheduling, and a maintenance crew was observed working WR '

The WRs observed were 10274 SWR for cleaning and inspection of the IVGHXB002 aftercooler tubes, and 503490PS for replacement of a diaphragm on IVGCPB002 Diesel Air Start Compressor The mechanics i were knowledgeable of the equipment and the tasks. The mechanics l familic.rity with the task led to performance of maintenance without i removing the procedure from its bag or opening it. The team reviewed ;

the procedure and determined all appropriate sign-offs had been made, and no procedural errors had been committe Several strengths were noted in the WR proces The' hanging of orange Work Request ID Tags on affected equipment helps alert others using the equipment of its status and helps avoid duplication of WRs. The planner's inspection of the defective equipment during the job planning phase is a strengt The concept of working items by train or division in a weekly rotation should help to limit problems with two trains being inoperable at the same time. The trip list concept is good, but could potentially be expanded to include system inoperable work lists to take advantage of system outages, as well as unit outage The working groups rotating shifts together is a strength, in that interpersonal relationships and a feelin; of teamwork can be deve'noa The veakness noted in this area was the mechanical maintenance meckonics use of procedures. Although no procedural errors were discovered, the crews did not have the procedures open while the work was being perfornied. Management needs to work harder to encourage full utilization of procedures, and encourage the mechanics to pro-vide feedback in case of inadequacies in the detail of procedures for covering the assigned tas . Planning Meetings The team observed several planning meeting Among the meetings observed were the daily planning meeting, the morning outage meeting, and the operating units morning meeting. The meetings were short, to the point, and effective. Participants were well prepared for discussion of items, and kept comments focused.

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.The . team inter. viewed the Transmission Group supervisor. ' Transmission

'does not have ' direct reporting to management. on the plant ' site, ;

but is a separate corporate group'. The group provides maintenance services for. components of greater than 600VAC!and the 1250C breake control power co'aponents and relaying. The technicians work , both '

nuclear and non-nuclear facilities in the Duke . system. -Transmission-has its own procedures, training program, -and equipment calibration program. Changes to' the station Mechanical or IAE groups programs may not be reflected in Transmission, due to 'its separate nature and ,

. reporting- authority. Transmission has a fraction of the resources 1 available for. procedure upgrades, training, or maintenance of test ,I equipment- that is available to other onsite maintenance group 'I j

The limited resources available to support these activit4s, which are considered normal overhead for a nuclear - plants maintenance group, will increase the need for monitoring 'to insure co.:pliance in safety related activities the group performs. The separate reporting authority. and duplication of support functions of Transmission !

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is considered a : weaknes This item will be ' followed - up under

IFI 50-413, 414/89-09-2 . Management support of Engineering Interviews conducted with Design Engineering, Performance Engineer-ing, and Maintenance Engineering, showed plant management-to be very supportive of these groups. Maintenance Engineering was encouraged to develop a Predictive Maintenance program. Funding for equipment '

was provided, and the group .was allowed to dedicate engineering staffing full time to the progra Maintenance Engineering was reorganized by component type to allow component expertise to develo Performance Engineering was provided support to fully implement a system engineer or system expert program. These experts use system requirements to evaluate equipment. In conjunction with the ]

component engineers from maintenance, this provides for a matrix fo <

the evaluation. of plant equipment. This will allow both component ;

and system limitations to be considered in evaluation )

l Interviews with Design Engineering stowed plant management is encouraging all groups onsite to work as a team in problem i resolutio / !

After interviewing the engineering groups, the plant manager was interviewed. He stressed a continuing concept of all the groups _ i wor king together to support plant operations. Congruence of goals in the different plant engineering groups with support of plant management is a strengt ,

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35 CFR 50.59 training The plant is currently developing a program for certification of individuals to perform 10 CFR 50.59 evaluation Knowledge of requirements and methods of performing the evaluations are being taught to individuals who, upon completion of training, will be certified ' level III' evaluator This program is seen as a strength, as it will allow for more consistent evaluation In the area of Plant Support there were no violations or deviations note . Action on Previous Inspection Findings (92701, 92702)

(Closed) DEV. 413,414/87-13-01, Failure to meet commitments of the approved PGP. The licensee provided documentation which indicatad that appropriate corrective actions had been take (Closed) VIO. 413,414/87-13-02, Failure to provide adequate training on calculation of subcooling margin. The licensee provided documentation which indicated that appropriate corrective actions had been take (Closed) IFI 413,414/87-21-01, Design and implementation of corrections to identified human engineering deficiencies. The licensee provided

' documentation which indicated that appropril 3 corrective actions had been take . Exit Interview (30703)

The inspection scope and findings for both the E0P and Operations / Support portions of this inspection were summarized in separate pre-exit inter-views during the inspection. The findings were again summarized with those persons indicated in paragraph 1 at the formal exit on May 16, 1989. The NRC described the areas inspected and discussed in detail the inspection . findings. Although proprietary material was reviewed during )

this inspection, no proprietary material is contained in this repor j i

Item Number Status Description / Reference Paragraph VIO 413/89-09-01 Open Valve 1-KC-9 found unlocked (paragraph 2.k) and operators not frisking immediately after exiting contaminated areas l (paragraph 2.e) l IFI 413,414/89-09-02 Closed Cold Leg Accumulator Boron concentration adjustment made

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l Item Number Status Description / Reference paragraph IFI 413,414/89-09-03 Open Thermal power computer calibration inputs not tracked on computerized tracking system (paragraph 2.b)

IFI 413,414/89-09-04 Open Weak 10 CFR 50.59 evaluation on Nuclear Service Water Modification (paragraph 2.c)

IFI 413,414/89-09-05 Ope Many of the sites safety related pump rooms are contaminated (paragraph 2.e)

IFI 413,414/89-09-06 Open Weak control of fire doors (paragraph 2.g)

IFI 413,414/89-09-07 Open Procedures for independent verification need improvement (paragraph 2.1)

IFI 413,414/89-09-08 Open Deficiencies noted during NS PT (paragraph 2.m)

IFI 413,414/89-09-09 Open Control of scaffolding needs to be improved (paragraph 2.r) ;

IFI 413,414/89-09-10 Open Site does not have DC ground fault locating equipment (paragraph 2.s)

IFI 413,414/89-09-11 Open There are many differences between the E0Ps and the PSTG (paragraph 3.a)

IFI 413,414/89-09-12 Open Correction of technical discrep-ancies contained in the E0Ps as outlined Appendix B (paragraph 3.b)

IFI 413,414/89-09-13 Open Correction of labeling discrep-ancies betwcen E0Ps and panel indication as outlined in Appendix D (paragraph 3.c)

IFI 413,414/89-09-14 Open Correction of S/G pressure meter

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indications (paragraph 3.c)

IFI 413,414/89-09-15 Open Correction of writer's guide discrepancies contained in E0Ps as outlined in Appendix C (paragraph 3.c)

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J Item Number Status Description / Reference-Paragraph IFI 413,414/89-09-16 Open Resolve control room noise level (paragraph 3.c)

I FI . 413,414/89-09-17 Open Review simulator. effectiveness in training on E0Ps (paragraph 3.d)

IFI 413,414/89-09-18 Open Weaknesses noted in the site's ETQS program (paragraph 4.a)

IFI 413,414/89-09-19 ' Open There are a significant number of TSMs on site, some ranging in , age of from 3 to 4 years. (paragraph 4.c)

- IFI-413,414/89-09-20 Cpen The seperate_ reporting authority and duplication. of ' support functions for the transmission group is considered a weakness (paragraph 4.j)

The following is a list' of the commitments. made by licensee _-personnel during this inspection:

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Licensee personnel committed to add calibration of themal powe computer inputs'to the computerized periodic Test Program for Unit 1 (see paragraph 2.b).

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Licensee personnel committed to sending Out of Calibration Notifica-tion Forms for the _ Unit 1 thermal power computer inputs to the systems Engineer ,(see paragraph 2.b).

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Plant management committed to review the procedures for and practices of plant operators concerning frisking when exiting contaminated -

areas (see paragraph 2.e).

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The SRG committed to investigate the purchase of Hochiki Detectors as a part of LER 413/89-011 (see paragraph 2.t).

The lice ;<e cumm, Lo&d t: r.<;ew and correct (as appropriate) the

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momemclature difficiencies in Appendix 0 (see paragraph 3.c and Appendix D).

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The license committed to evaluate the discrepancies in Appendices B and C (see paragraph 3.c and appendices B and C).

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The licensee committed to resolve the conflict between EP/1/A/5000/01 and the markings on the S/G pressure meters (see Appendix B, para-graph 1.g).

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APPENDIX A PROCEDURES REVIEWED AP/0/A/5500/20 LOSS OF NUCLEAR SERVICE WATER 10/29/87 AP/0/A/5500/22 LOSS OF INSTRUMENT AIR 06/02/88 AP/0/A/5500/31 ESTIMATE OF FAILED FUEL BASED ON I-131 02/19/88 CONCENTRATION AP/0/A/5500/34 SECONDARY CHEMISTRY OUT OF SPECIFICATION 11/04/88 AP/1/A/5500/02 TURBINE GENERATOR TRIP 03/13/89 AP/1/A/5500/03 LOAD REJECTION 03/31/87 AP/1/A/5500/04 LOSS OF REACTOR COOLANT PUMP 10/20/86 AP/1/A/5500/05 ECCS ACTUATION DURING PLANT SHUTDOWN 06/18/87 AP/1/A/5500/06 LOSS OF S/G FEEDWATER 03/05/87 i AP/1/A/5500/07 LOSS OF NORMAL POWER 06/06/88 AP/1/A/5500/08 MALFUNCTION OF REACTOR COOLANT PUMPS 08/18/86 AP/1/A/5500/10 REACTOR COOLANT LEAK 01/16/89 AP/1/A/5500/11 INADVERTENT NC SYSTEM DEPRESSURIZATION 03/13/89 AP/1/A/5500/12 LOSS OF CHARGING OR LETDOWN 04/02/86 AP/1/A/5500/13 BORON DILUTION 01/07/87 AP/1/A/5500/14 CONTROL ROD MISALIGNED 06/06/84 AP/1/A/5500/15 R00 CONTROL MALFUN TION 03/24/87 AP/1/A/5500/16 MALFUNCTION OF NUCL TR INSTRUMENTATION SYSTEM 11/07/87 AP/1/A/5500/17 LOSS OF CONTROL ROOM 01/31/89 AP/1/A/5500/18 HIGH ACTIVITY IN REACTOR COOLANT 03/15/88 AP/1/A/5500/19 LOSS OF RESIDUAL HEAT REMOVAL SYSTEM 11/30/88 AP/1/A/5500/21- LOSS OF COMPONENT COOLING 12/22/87 AP/1/A/5500/23 LOSS OF CONDENSER VACUUM 11/13/86 AP/1/A/5500/24 LOSS OF CONTAINMENT INTEGRITY 01/08/87 AP/1/A/5500/25 DAMAGE 0 SPENT FUEL 09/10/87 AP/1/A/5500/26 LOSS OF REFUELING CANAL OR SPENT FUEL POOL LEVEL 05/29/86 EP/1/A/5000/1 REACTOR TRIP OR SAFETY INJECTION 03/13/89 EP/1/A/5000/1A REACTOR TRIP RESPONSES 03/13/89 EP/1/A/5000/1A1 NATURAL CIRCULATION C00LDOWN 03/13/89 EP/1/A/5000/1B S/I TERMINATION FOLLOWING SPURIOUS S/I 03/13/89 EP/1/A/5000/1C HIGH-ENERGY LINE BREAK INSIDE CONTAINMENT 08/01/88 EP/1/A/5000/1C1 S/I TERMINATION FOLLOWING HIGH-ENERGY LINE BREAK 08/01/88 IN CONTAINMENT EP/1/A/5000/1C2 POST LOCA C00LDOWN AND DEPRESSURIZATION 03/01/89 EP/1/A/5000/1C3 TRANSFER TO COLD LEG RECIRCULATION 08/01/88 EP/1/A/5000/1C4 TRANSFER TO HOT LEG RECIRCULATION 08/01/88 EP/1/A/5000/1C5 LOSS OF EMERGENCY COOLANT RECIRCULATION 08/01/88 !

EP/1/A/5000/1C6 LOCA OUTSIDE CONTAINMENT 08/01/88 l EP/1/A/5000/10 STEAM LINE BREAK OUTSIDE CONTAINMENT 03/13/89 EP/1/A/5000/1D1 S/I TERMINATION FOLLOWING STEAM LINE BREAK 08/01/88 EP/1/A/5000/1E STEAM GENERATOR TUBE RUPTURE 03/01/89 '

EP/1/A/5000/1El POST-S/G TR ALTERNATE C00LDOWN AND 03/13/89 ;

REPRESSURIZATION l EP/1/A/5000/IE2 S/G TR ALTERNATE C00LDOWN USING BACKFILLING 03/13/89 EP/1/A/5000/1E3 S/G TR WITH CONTINUOUS NC SYSTEM LEAKAGE- 03/01/89 ,

SUBC00 LED REC 0VERY j EP/1/A/5000/1E4 S/G TR WITH CONTINUOUS NC SYSTEM LEAKAGE- 03/01/89 i SATURATED RECOVERY I

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EP/1/A/5000/IE6 S/G TR C00LDOWN USING ND 08/01/88 EP/1/A/5000/2 CRITICAL SAFETY FUNCTION STATUS TREES 08/01/88 EP/1/A/5000/2A1 NUCLEAR POWER GENERATION /ATWS 03/01/89

.EP/1/A/5000/2A2 LOSS OF CORE SHUTDOWN 08/01/88 EP/1/A/5000/2B1 INADEQUATE CORE COOLING 08/01/88 EP/1/A/5000/2B2 DEGRADED CORE COOLING 08/01/88 EP/1/A/5000/2B3 SATURATED CORE' COOLING CONDITIONS 08/01/88 EP/1/A/5000/2C1 LOSS OF SECONDARY HEAT SINK 08/01/88 EP/1/A/5000/2C2 S/G OVERPRESSURE 03/01/89 EP/1/A/5000/2C3 S/G HIGH LEVEL 03/01/89 EP/1/A/5000/2C4 LOSS OF NORMAL STEAM RELEASE CAPABILITIES 08/01/88 EP/1/A/5000/2C5 S/G LOW LEVEL 03/01/89 EP/1/A/5000/201 IMMINENT PRESSURIZED THERMAL SHOCK CONDITIONS 03/01/89 EP/1/A/5000/2D2 ANTICIPATED PRESSURIZED THERMAL SH0CK CONDITIONS 03/01/89 EP/1/A/5000/2D3 HIGH PRESSURIZER PRESSURE 03/01/89 EP/1/A/5000/2E1 HIGH CONTAINMENT PRESSURE 03/01/89 EP/1/A/5000/2E2 HIGH CONTAINMENT SUMP LEVEL 08/01/88 EP/1/A/5000/2E3 HIGH CONTAINMENT RADIATION LEVEL 08/01/88 EP/1/A/5000/2F1 PRESSURIZER FLOODING 08/01/88 EP/1/A/5000/2F2 LOW NC SYSTEM INVENTORY 08/01/88 EP/1/A/5000/2F3 VOIDS IN REACTOR VESSEL 08/01/88 EP/1/A/5000/3 LOSS OF ALL AC POWER 08/01/88 EP/1/A/5000/3A LOSS OF ALL AC POWER RECOVERY w/o S/I REQUIRED 08/01/88 EP/1/A/5000/3B LOSS OF ALL AC POWER RECOVERY WITH S/I REQUIRED 08/01/88 PROCEDURES REFERRED TO BY E0P OR AOP THAT WERE REVIEWED (IN FULL OR IN PART)

OP/0/A/6200/08 ICE CONDENSER REFRIGERATION SYSTEM OP/0/8/6100/13 STANDBY SHUTDOWN FACILITY OPERATIONS OP/1/A/6150/02A REACTOR COOLANT PUMP OPERATION OP/1/A/6450/10 CONTAINMENT HYDROGEN CONTROL SYSTEM 02/12/86 OP/1/A/6700/01 UNIT ONE DATA BOOK OP/1/B/6250/078 AUXILIARY ELECTRIC BOILER 09/09/86 OP/2/B/6250/07A AUXILIARY STEAM SYSTEM ALIGNMENT 01/04/89 DOCUMENTS UTILIZED DURING E0P REVIEW EMERGENCY PROCEDURE GUIDELINE SETPOINTS 05/14/86 CATAWBA NUCLEAR STATION EMERGENCY PROCEDURE GUIDELINES (PSTG) SEP 1988 WESTINGHOUSE OWNERS GROUP EMERGENCY RESPONSE GUIDELINES: HP VERSION 09/0l/83 REVISION 1A CATAWBA NUCLEAR STATION WRITER'S GUIDE FOR EMERGENCY AND ABNORMAL 03/09/88 PROCEDURES

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APPENDIX B TECHNICAL AND HUMAN FACTORS COMMENTS This appendix contains technical and human factors comments, observations and suggestions for E0P improvements made by the team. Unless specifically stated, these comments are not regulatory requirements. However, the licensee agreed in each case to evaluate the comment and take appropriate action. These items will be reviewed during a future NRC inspection as noted in paragraph General comments: The SPD provides operator action setpoints which are required b/ the CNS E0P There is no SPD to serve A0P unique requirement . Operation of the SSF is conducted under an O Since the use of the SSF presumes the control room and the alternate shutdown panel have been abandoned, SSF operation is an abnormal condition. SSF operation should be governed by. a procedure which has the added control and review provided by E0Ps and AOP . AP/0/A/5500/34,- secondary chemistry out of specification, treats out-of-specification actions by a three case analysis and corrective response process, by operating mode. The process is an excellent method of treating this type proble . In the opinion of the team, EP/1/A/5500/203, high pressurizer pressure, and the companion modification which added the pressurizer pressure (2400 psig logic to the integrity critical safety function tree in procedure EP/1/A/5000/2 were a significant improvement over the ERG integrity treatmen . Many differences exist between the ERG and the PSTG. The majority are ERG mitigation sequence differences. The licensee stated that all differences were evaluated and that deviations were documented for those differences found to be safety significan Those which were not safety significant were not documented. The team considers all mitigation sequence differences as safety significan . E0P changes can be originated by CNS or the general offic Since the CNS staff does not use the PSTG during the E0P change development process, the burden of ensuring that the E0Ps conform to the PSTG falls entirely upon the general office staf In view of. the importance of maintaining conformance, the PSTG must be utilized during the development of E0P changes.

PSTG DEV Only EP 01 and 03 contain entry conditions; the remaining E0Ps do not. The licensee stated that entry conditions were not required because entry is by transfer from either EP 01 or EP 0 The team noted that the PSTG lists entry conditions for all E0P The team considers the absence of entry conditions in E0Ps as a deviation from the PSTG and ER __ . _ _ .. . - _ - _ _ _ __ i

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B-2 II. EP portion of the E0P comments: EP/1/A/5000/01 Reactor Trip Or Safety Injection i Step 18: The E0P and the PSTG deviate from the sequence in the ERG and no deviation has been provided. In the ERG, " Check If RCS Is Intact" occurs before " Check If SGs Are Not Faulted." Step 5-14: These E0P steps and PSTG steps are listed as subse-quent actions, unlike the ERG which list them as immediate actions and no deviation is documente PSTG DEV Step 6: Steps 6 and 7 in EP01 are in the reverse order of the PST Steps 7 and 10: These steps require the operator to check the monitor light panel for proper S/I alignmen The monitor lights are arranged in group.s. Not all lights in a given group are lit on receipt of an S/I signal. This makes it much more difficult for the operator to verify proper S/I equipment alignment. The licensee had previously i'lentified these discrepancie Examples of these discrepancies are:

(1) On the Ss panel, the actuation signal for windows D6, 07, E6, and E7 has been changed and they are no longer actuated by an Ss signa (2) On the St panel, windows A6, A7, B6, and B7 light on an Ss signal. The rest of the St panel is off on an Ss signa (3) On the St panel, the actuation signal for windows L11 and L12 has been' changed to an Sp signal, but they are still located on the St pane l (4) On the St panel, windows F4, F5, and F12 remain da) K for approximately 15 to 20 minutes after an St signal. The rest of the panel is lit during this tim PSTG DEV Step 1: This step contains a kick-out to an A0P unlike the corresponding step in the PST Step 4: None of the status light panels in the Control Room have alpha numeric demarcation necessary for ease of locatio Step I.4, RNO: This step requires the operator to check whether S/I is required based on a S/G pressure of 725 psi The "S/G PRESS" meters in the control room have indicated in red

"SI" at 710 psig. This Item was previously identified in NRC INSPECTION REPORT NOS. 50-413/87-13 AND 50-414/87-13, 7.0.2 page 20, dated August 6, 1987. This is a safety significant item which the licensee has committed to resolve. Resolution of this

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B-3 Step 6c.: This step specifies operator action based on a meter reading of 195 psig; a value which can not be read. The meter has a range of 0 to 3000 psig and is graduated in 50 psig increment . Step 6d.: This step requires operator action at 500 gpm ND flow; a value which cannot be rea Enclosure 3: In the first and second bullet, the pot setting corresponding to a pressure of 1090 psig is not include Step 18: This step requires operator action at a containment sump level of 0.5 ft or greater. The operator can not dependably read this value on the meter. 0.5 ft is-the bottom of the' meter scal In addition, the meter erroneously read 0.75 ft with a dry. sump at the time of the inspectio . Step 29: The values given for PRT pressure, level, and tempera-ture in each of the three bullets do not agree with either the alarm manual or the setpoint documen . EP/1/A/5000/1A Reactor Trip Response PSTG DEV Step 1 thru 3: Steps 1 thru 3 are not contained in the-PSTG or the ER PSTG DEV Step 4: This step is conducted prior to the corre-sponding steps 1-9 of the PSTG vice after i Step 17 fourth bullet: The' step states "Stop one CF pump." If only one CF pump is running, all CF would be los . EP/1/A/5000/1A1 Natural circulation cooldown PSTG DEV Step 9: There is no caution prior to this step indicating that S/I will unblock if reactor coolant system pressure increases above 1955 psig as there is in the PST Step 11: The E0P and the PSTG do not indicate that subcooling should be based on core exit thermocouple as does the ERG and no deviation is documented,

'~ PSTG DEV Step 13: This step does not contain a substep which ensures letdown is in service, nor its associated RNO, as does step 12c of the PST PSTG DEV Step 17: This step does not contain a substep which ensures letdown is in service, nor its associated RNO, as does step 17c of the PST _ _ _ - _

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B-4 PSTG DEV Step 31: The caution concerning depressurizing the reactor coolant system is contained after this step vice before as in the PSTG. Additionally, this caution does not include a statement directing the maintaining of .the subcooling require-ments of step 17 as in the PST The training department does not have an established scenario for training operstors in how to control the reactor.with a void in the hea .

I EP/1/A/5000/1B S/I Termination Following Spurious S/I

. Step 13c1 RNO: The labeling on the reference instrument is misleading and makes location difficult. The meter actually indicates the RN to the KC HX outlet flow, Step 13c2 RNO: The step does not reference the procedure number for aligning R Step 29 page 25 first bullet: Valve 1-NM3A is not include i EP/1/A/5000/1C High energy line break inside containment

' Step 1, note: This note is actually a conditional step. It is required within step 1 prior to the actions called for in substep Step 8, caution: This caution is actually an action step. It is required within step 8b RNO, which also requires a condition step beginning "IF PZR pressure is greater than 2315 PSIG." Step 15, caution: This caution is an action step related to the completion of step 1 Step 18c: This step is not a substep required to accomplish high level step 18. It constitutes an additional high level step in this procedur Step 23c: The "CLOSE/ RESET" pushbutton on ISM-1 is a dual purpose pushbutton used both to close the MSIVs as well as reset the MSIV bypass valves. If the pushbutton is used while the MSIVs are open, the MSIVs will close. This system holds consid-erable risk of inadvertent closure of an MSIV, and this accident has occurred in the past. Single purpose controls are required to eliminate this proble Step 23d, note: This note is a caution identifying a potential hazard for increased of fsite radiation release when dumping steam from the S/Gs.

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system within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months tfter actuation.

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execution of the entire sectio . EP/1/A/5000/1C1 S/I Termination Following High Energy Line Break

. Inside Containment PSTG DEV Step 5: Phase A containment is reset in step 5'of the E0P.' The equivalent step is not performed until . step 13 of the PST PSTG DEV Step 3a RNO: This step does not direct the operator to the step " aligning charging. flow path" as does step 2 RNO o the PST ~

Step 4: There is no guidance on which indication toluse for subcooling. There are three different -indications given on the plasma. display, Step 9a: There is no guidance defining " desired charging flow".

Transferring to auto with a large error signal' could cause- the valve to fail, Step 27: The usage of the 50 deg. F subcooling limit'is incon-sistent with the ERG and the setpoint documen . . EP/1/A/5000/1C2 Post-loca cooldown and depressurization Step.1, caution: This caution statement is actually two notes providing -supplemental information for the performance:of step Step 4, caution: This caution includes a conditional statement that is actually the first substep of step It is required prior to the action described in step 4 l8 Step 9b, RNO: This conditional step is out of sequence. It is required just prior to step 9 Step 9d, note: This note is actually a caution related to the performance of step 9d. It also contains a conditional sequence required just prior to step 9d .1

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B-6 . Step 12 b, RNO: This conditional step is out of sequenc It is required just prior to step 12 Step 12d, caution: This caution statement is actually a note that provides supplemental information for the performance of the remainder of step 1 Step 12f, note: This note is actually a caution related to the performance of step 12f. .It also contains a conditiona sequer.ce required just prior to step 12f Step 12f4: The desired cooldown rate mentioned in this step is defined quantitatively in step 12d on the previous pag Quantitative definition of the cooldown rate is required in this step to reduce operator memory burden and eliminate a transition-backwards within the procedur . Step 17, note: Both note statements are actually cautions related to the performance of step 1 Identification of the potential hazards are required within these caution Step 20, caution: This caution contains an action step that is required prior to the performance of step 20c. Identification

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of the potential hazard is required within this caution, Step 32, caution: This caution is actually a step related to the performance of step 3 . Step 33, caution: This caution contains an action step related to the performance of step 33. Identification of the potential hazard is required within this cautio . EP/1/A/5000/1C3 Transfer to cold leg recirculation Step 1: The E0P and the PSTG, prior to this step, do not have a caution concerning taking manual actlon to restart safeguards equipment if offsite power is lost as does the ERG and no deviation is documente Step 2: The E0P and the PSTG perform this step before S/I is reset vice after as does the ERG and no deviation is documente PSTG DEV Step 6: The E0P does not contain the caution that if pressure increases above the NI pump shutoff head the NI pumps should be stopped.as does the PST PSTG DEV Step 13b, RNO: This step does not refer to FR- " Response to high containment pressure", as does step 9c, RNO of the PST _ _ - - - - _ _ _ - - _

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9. EP/1/A/5000/1C4 Transfer to hot leg recirculation Step 1, caution: This caution is actually an action step 1 required at the beginning of the substeps to step . EP/1/A/5000/1C5 Loss of Emergency Coolant Recirculation Step 3c: This step does rot specify which subcooling indication to us l Steps 3c and d: These steps instruct the. operator to start and stop the NV and NI pumps, but do not provide pump duty cycle restriction Step 5: This step and step 4 of 'the PSTG secure all NC pumps unlike the ERG which leaves one running. No deviation is documente j Enclosure 3 and other comparable enclosures: These enclosures do not provide the number of the key necessary to unlock the CLA isolation valve electrical breakers. During the inspection, the wrong key for operating the breaker was issued to the operato Step 3d first bullet: This step does not use maintenance of -

subcooling greater than or equal to zero as a criteri i Step 18 and 22: There is no direction after these steps to return to the procedure in effec Step 19: There is no note warning the operator to monitor containment sump level nor ND pump curren . EP/1/A/5000/1C6 Loca outside containment 1 No comment . EP/1/A/5000/10 Steamline break outside containment Step 3: This step and step 3 of the PSTG do not verify S/G l blowdewn isolation of the faulted S/G(s) as does the ERG and no 1 deviation is documented. PSTG DEV Step 8: This step does not check intermediate range flux prior to S/I termination as does step 7c of the PST PSTG DEV Step 8b: This step checks " total feed flow" where as step 7b of the PSTG checks "CA flow". i i

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B-8 13. EP/1/A/5000/1D1 S/I . Termination Following Steam Line Break Step 3: The preferential order of depressurization differs from the similar. step in other EP Step 27b: The placement of the note obscures the ste . EP/1/A/5000/IE Steam generator tube rupture Step 3b RNO 2d: Since the PORV is known to be.open, " ensure" is incorrec The appropriate action verb is close, Step 3d RNO: As implied by the preceding caution, this step works well unless the CA turbine pump is running as the only pump; in that case it will shut the pump down. The RNO step should be expanded to provide an action sequence in the event the turbine pump is the only running pum Step 20b RNO la: The step directs that S/I pumps be started "to restore subcooling and PZR level". The step should be revised to ensure that' PZR level and subcooling are restored prior to continuing to the sub step which transfers back to step Step 30a and elsewhere in other S/G TR procedures: The table compares trends in pressurizer level and S/G level in an attempt to determine subsequent mitigation strategy. Since pressurizer level control is in automatic pressurizer level will remain constant, within broad limits, in spite of water transfer through the brea For this reason, the team concluded .that the table was not a suitable method of determining mitigation strateg Step 34: The step does not direct periodic sampling of the turbine buildina sum Enclosure 1, step F: The step does not place OAC point ID P0828 on a trend recorde Enclosure 1, step B: The S/I termination criteria parmits S/I to be terminated prior to sufficient primary depressurization following a S/G tube ruptur . EP/1/A/5000/IE1 Post-S/G TR cooldown and depressurization l- Step 10, table: As discussed under E0P EP IE comments in this l report, the table relating PZR and S/G level trends is not valid if PZR level control is in automatic.

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16. EP/1/A/5000/IE2 S/G TR alternate cooldown using backfill The SPD value is 150 ppm for backfill margin, not 170 as shown in the E0P. The latter is correct. This value is recalculated for each fuel cycl Rather than change the SPD each time, a controlled document calculation. Sheet is issued to provide updated backfill margi The team considered this practice acceptable- Step 1, caution: The second bulleted caution is actually an action step that is required for performance' of this procedur The third bulleted caution is actually a note along with an action step that is required for the performance of this procedur Step _5, caution: This caution is structured as an action and fails to identify the related potential hazar Step 12, caution: This caution is actually a note. However it has no relation to the remaining steps in this procedur The actions it addresses are included in the procedure referenced in step 13, and that procedure contains the necessary informatio . EP/1/A/5000/IE3- S/G TR with continuous NC leakage: subcooled recovery Step 28b RNO: Typo; the reader should be referred to steps 33-35, not 32-3 Caution before step 34: This discusses rack out of NI or NV pumps; it should discuss rack out of pump breaker Step 37. There is no requirement listed for periodic HP sampling of the Turbine Building sum . EP1/A/5000/IE4 S/G TR with continuous NC system leakage: saturated recovery Step IES: Typo; change NV to N Step 38: The Turbine Building sump should be sampled periodi-call . EP/1/A/5000/IE6 S/G TR cooldown using ND When the ERGS place decay heat removal in service with S/G TR, the process is listed within each ERG. The licensee chose to j create IE6 as a single procedure which covers all decay heat removal with S/G TR via a transition to IE6. The team evaluated !

this as a positive addition to the CNS E0P !

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q 1: 43% which the setpoint document describes as fuel mid plane level with zero void fraction. The ERG requires this value to be 3.5 ft above the bottom of active fuel with zero void fraction. The conflict between the ERG 3.5 ft requirement and the CNS use of mid plane is not a documented deviation. However, this difference from the ERG was documented in a Duke letter of August 29, 1984 to the NRC (Tucker /Denton). CSF 2C: The CNS provides feed flow only to intact generators; the ERG does not limit flow to only intact generators. No deviation exist CSF 2D: When compared to the ERG, the changes made to the CNS CSF integrity tree were significant enhancements which were supported by valid deviations. In the opinion of the team, the CNS treatment of the coolant integrity tree was excellent, particularly with reference to cold overpressure protectio PSTG DEV CSF 2E: The PSTG and the E0P logic use a containment sump design flood level of 13 f The number in the SPD is 17 ft.

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2 EP/1A/5000/2A?. Nuclear Power Generation /ATWS Step 4f RNO: The step directs opening of all PORVs and does not allow for use of just one POR . EP/1/A/5000/2A2 Loss of Core Shutdown Nc comment 2 ED/1/ /5000/2B1 Inadequate Core Cooling- Step 24: This . step does not specify the minimum procedural criteria for sta ting and running an NC pum Step 27: This step specifies' operator action based on a meter reading of 195 psig; a value which can not be read. The meter

.has a range of 0 to 3000 psig and is graduated in 50 psig increment c, Step 31: This step ' cannot be reached from any point in the procedur . EP/1/A/5000/2B2 Degraded Core Cooling Step 17b: Step 17b list the D/P for two conditions (Train A and Train _B) Steps 17c and 17d only ask for D/P. There is no guidarre to the operator if, due to operating conditions, the D/Ps were.different between train A and train Step 24: There is no way to enter step 24. Step 23 is a GO T0 statemen . EP/1/A/5000/283 Saturated Core Cooling Conditions No comment l

2 EP/1/A/5000/2C1 Loss of secondary heat sink Step 7: This step establishes CA flow to "at least one" S/G which means ficw could be restored to all four S/Gs. Since the S/Gs are " dry", CA flow should be established to the minimum number of S/Gs required ta restore the heat sink to avoid unnecessary thermal shoc Step 8 and elsewhere in this and other procedures: The logic is based upon total CA flow. No total CA flow meter exists. The operator is required to sum flows from individual S/G sensor _ _ - _ - _ _ _ _ _ _ - - _ _ _ _ _ - _ . _ _ - _ - _ - _ _ _ _ _ _ - _ - _ _ _ . _ _ _ - _ _ . _ _ _ . _ _ _ - _ _ _ _ _ . . _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ _ _ -

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B-12 Step 12 and elsewhere: The feed regulator bypass valves are about 37 ft above the floor leve Since the valves have vertical rising stems, it would be difficult to install chain operator Interference limits the potential for use of a

. ladder; no ladder long enough to reach the valves could be foun No emergency lighting was available in the vicinit Str7 17 RNO 2: Typo; change "ro" to "no", Steps 23bic & 23b2b: One step uses "C/L", the other "C-Leg" to designate cold le The spare annunciators on the MD panels are either black faced or blank. A standi i convention has not been followe Step 37 RNO a, second alternative: The operator should be required to ensure the head vents are closed prior to the transfer to EP I Encl 2: The procedure does not include a requirement to report action complete to the Control hoo '27. EP/1/A/5000/2C2 S/G overpressure Step 10, caution: This caution fails to identify the potential nazard as required by the writers guid . EP/1/A/5000/2C3 S/G high level Step 10: The RNO directs action to be taken if the verifica-tions in either step 10a or step 10b are not met. However, with the existing step format the RNO only applies to step 10 . EP/1/A/5000/2C4 Loss of normal steam release capabilities Step 1, caution: This caution fails to identify the potential hazar . EP/1/A/5000/2C5 S/G low level No comments 31. EP/1/A/5000/2D1 Imminent pressurized thermal shock condition Step Id1 RNO: Typo, the step is supposed to read "NC" tempera-ture, not "NV" temperatur Enclosure 4: The enclosure is illegibl _ _

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B-13 32. EP/1/A/5000/2D2 Anticipated pressurized thermal shock, Enclosure 3: The enclosure is illegibl . EP/1/A/5000/2D3 High pressurizer pressure Step 3: The if/then step may require initiation of NV aux spray. The method is not specified. Use of NV aux spray is infrequent. In the AOPs, when NV aux spray is required, the method is specifie Step 21: Use of the word maintain is incorrect. Boron addition establishes a new concentratio PSTG DEV Caution: The PSTG FR-P.3 initial caution concerning restoration of pressurizer pressure control was not included in the E0P. Procedore step 5 addresses the same subject but an action step cannot fully accomplish the intent of a cautio PSTG DEV E0P step 23 requirement to ensure adequate shutdown margin before returning to the procedure in effect does not appear in the PSTG. This is a valid addition to the E0Ps which is not currently in the PST . EP/1/A/5000/2E1 High con,ainment pressure Step 2, note: This note is actually a caution. It requires identification of the related potential hazard. In addition, an action step is included in the note that is required prior to performance of step 2 Step 3, caution: This caution statement is actually a condi-tional step that applies throughout the procedur It is appropriately placed on a foldout page for this procedure, Step 3, note: This note is actually a conditional step that is required within the procedure prior to the actions included in step Step 5, caution: This caution fails to identify the related hazard. In addition, it is incorrectly structured as an action, rather than as an alert to personnel about potential damage or injur Step 7b, RNO: This step is overly complex, with multiple possible meanings due to the combined use of the logic terms AND and O i a------ _ - - . _

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E Step 11, note: The first bulleted item in this note is unneces-sary. This concern is a basic training issue, and need not be included as a note here. The second bulleted item is a conditional step. It is required within the procedure prior to the actions included in step 1 Enclosure 4, step 2c: The bulleted items within this step are actually conditional sequences and are not in accordance with the format for logic statements found in the writer's guid . EP/1/A/5000/2E2 High containment sump level Step 2a: The sequencing of containment isolation valves within this step is awkward ' and inconsistent with the placement of valve switches on the control board . EP/1/A/5000/2E3 High containment radiation level No comment 37. EP/1/5000/2F1 Pressurizer flooding Step 2: From the definitions in the writer's guide, the use of-verify followed by ensure is incorrect. Verify does not permit a status change; ensure requires a status change if not as liste . EP/1/A/5000/2F2 Low NC system inventory No comment . EP/1/A/5000/2F3 Voids in reactor vessel Step 1: There is no caution prior to this step nor step 1 of the PSTG warning against use of this procedure if a controlled cooldown is in progress and a void in the head is expected, a:
does the ERG and no deviation is dacumente Step 4, RNO b(2): This step does not give guidance defining
" minimum charging". Step 14: This step and step 9 of the PSTG are not preceded by a caution alerting the operator to evaluate the status of any reactor coolant pump prior to starting it if seal cooling had previously been lost as does the ERG and no deviation is documente Step 14: This step and step 9 of the PSTG are not preceded by a note informing the operator of the priority for starting reactor coolant pumps as does the ERG and no deviation is documented.
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B-15 PSTG DEV Step 17: This step does not direct the closing of both valves in a vent line with a failed valve as does step 12 of the PST Step 20d: This step sends an operator inside containment with up to 6% hydrogen concentration present, PSTG DEV Step 26: This step does not direct the closing of both valves in a vent line with a failed valve as does step 20 of the PST . EP/1/A/5000/03 Loss of all ac power PSTG DEV This procedure does not list entry conditions at the beginnini of the procedure as does the PSTG. The E0P as written contains symptoms at the beginning of the procedure. However, these are not clear enough to prevent inadvertent entry into the procedur Step 3, RNO: The valves in this step which are ensured to be open will not have power available to their control board indications during a loss of all ac powe Step'3: The E0P and the PSTG, in this and subsequent steps do not list " Verify NC System isolation" and " Ensure CA flow to S/G(s)" as immediate actions as required in the ERG. The PSTG does not specify any immediate actions for any procedures contrary to the ERG and no deviation is documente Step 7: The E0P and the PSTG do not contain a caution prior to this step alerting the operator to reset an S/I signal to permit manual loading of equipment as does the ERG and no deviation is documente Step 7: The E0P and the PSTG do not contain a step prior to this step to ensure that CST inventory is conserved for makeup to the steam generators as does the ERG and no deviation is documente Step 7: This step and step 12 of the PSTG check steam generator isolation but do not address feedwater isolation as does the ERG and no deviation is documente Step 10: This step and step 15 of the PSTG direct maintaining steam generator levels at no-load level instead of maintaining them within the band established in the ERG and no deviation is documente Step 11a: This step and step 16a of the PSTG do not contain adverse containment values for steam generator narrow range level a* Joes the ERG and no deviation is documente _ - _ _ _ _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ . _ _ _ _ _ _ _ ___ _ ._. _ _ . _ . . _ - _ _ _ _ _ _
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L i . Step 11b: This step directs an operator to unlock valve These valves do not have locks on them and are not designated as l.- locked valves on the prin Step 12b: This step directs an operator to ensure that ICA-6 is closed. This valve can not be operated locally with ladders provide Step 12d: This step checks hotwell level < 6 inches. The required meter is graduated in fee . PSTG DEV Step 12e: This step does not isolate the CA pump suction from condensate grac'e sources as does step 17e of the PST Step 16e: This step references figure 6.10 of the curve boo The correct figure is PSTG DEV Step 16e: This step maintains S/G pressure at a value based on NC criticality temperature limi The PSTG directs maintaining S/G pressure at 10f psi Step 18: This step and step 23 of the PSTG do not address checking source range instrumentation to verify reactor shutdown as does the ERG and no deviation is documente Step 27: This step and step 32 of the PSTG are not preceded by a caution against exceeding the capacity of the power source as does the ERG and no deviation is documente . EP/1/A/5000/3A Loss of all ac power recovery without S/I required PSTG DEV Step Sh: This step ensures only %e 4V pump is running whereas step 4e of the PSTG directs star + mg all avail-able NV pump Step 7e: This step directs establishing " desired charging flow" and does not define it as a value comparable to normal NI pump miniflow as does the ERG and no deviation is documente Step 10: The E0P and PSTG do not contain a note prior to this step to prevent inadvertent start of the motor drlven auxiliary'
feedwater pumps as does the ERG and no deviatien is dccumente PSTG DEV Step 15: This step does not start an additional NV pumn as does step 14a of the PST Step 16: This step and step 15b of the PSTG do not check let-down in service n,or direct use of auxiliary spray to control NC system pressure as does the ERG and no deviation is documente _ . _ - _ . - _ _ _ _ - _ _ - _ _ _ _ _ _ _ _ - _ - - - - _ - _ - - _ - - - - - _ _ - -
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B-17 4 EP/1/A/5000/3B Loss of all ac power recovery with S/I required Step 8: The E0P and the PSTG do not contain a step prior to this step which places the containment spray pump switches in standby as does the ERG and no deviation is documente Step 8: The E0P and PSTG do not contain a note prior to this step to prevent inadvertent start of the motor driven auxiliary feedwater pumps as does the ERG and no deviation is documente Step 11: This step and step 10 of the PSTG direct transition to E-0, " Reactor trip or safety injection" instead of E-1, " Loss of reactor or secondary coolant" as does the ERG and no deviation '
is documente III. AP portion of the E0P comments: AP/0/A/5500/20 Loss of nuclear service water Paragraph A, purpose: On line two, after " loss of RN train or" some wording has been omitted. The remainder of the sentence does not make sens . AP/0/A/5500/22 Loss of instrument air Page 1: The enclosure listing and the actual enclosures are untitle This makes selection of the proper enclosure diffi-cul Pg. 1, step B: Use of "and/or" is prohibited by the writer's guide, Pg.5, step 6: Neither the procedure nor enclosure 3 note that realignment of the turbine aux feed pump to S/G A or C requires operation of CA38A or CA668, Encl. 1, pg. 15: Contrary to most CNS drawings, drawings j CN1594-1.2, CN1594-1.3, CN2594-1.2 and CN 2594-1.3 do not the
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list fail position for air operated valve Encl. 1, pgs. 20 & 21: The fail positions for IKC-122 and 2KC-122 are open, not closed as show Encl. 1, pgs. 24 & 26: Valves 1NV-309 and 2NV-309 are missing from the lis Encl. 2, step 3: This step requires the IAEs to install port-able air bottles and open some letdown valves. IAE personnel are not trained on the A0Ps. No IAE procedure reference is provide _- ._ . _ _ .
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i Encl. 2, step 4: The order of the two "or" gated substeps appears to be reversed since opening the 45 gpm letdown orifice would allow the control room to control inventory with NV-11 i Encl. 3, step 2: It is not clear in this step whether the
" check and "IF" statements apply to at least one, more than one, all, etc. S/Gs? AP/0/A/5500/34 Secondary chemistry out of specification No comment . AP/1/A/5500/02 Turbine generator trip Step Cla: The step does not give the expected P-9 light status or panel locatio Step Did: Typo, Should be "D.3" not "d.3". Step D1 RNO: Typo, Should be "D.2" not "d.2". Step 05 Note: The note is unclear in that it- does not specify
" Transformer" cooling bank Step D7 RNO first bullet: There are two switches with the same name. Currently the operator cannot distinguish the difference in switche Step D7 RNO second bullet: There are two switches with the same name. The operator neads to be able to distinguish the difference in switche Step D13: The step does not provide an RNO if the steam dumps are not availabl Step D2e: The procedure does not address the method of rod control below 15% powe . AP/1/A/5500/03 Load Rejection Step D4 note: There is no operator guidance given as to where to read the 3 deg. delta Tave-Tref, Step D10 Note: See 4.d above, Step D14c RNO third bullet: There are two switches with the same name. The operator needs to be able to distinguish the difference in switche _ _ _ - - _ __. _
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d-19 1 . Step D14c- RNO second bullet: There are two switches with the same name. The operator needs to be able to distinguish the difference in switche Step D15 the second bullet: The graduation of the meter is such that an. operator can not determine + or .1 KV .
. Steps D16c rnd d: The steps contain six separate actions and they are written in two step Steps D16f and g: The steps contain six separate actions and they are written in two step Step D18: The temperature given for the PRT action point is inconsistent'with the temperature given in the E0 . AP/1/A/5500/04 Loss of reactor coolant pump No comments AP/1/A/5500/05 ECCS actuation during plant shutdown Step 15c: The list of OAC point identifiers is inconsistent and not in accordance with the placement of these points on the computer screens. However, all of the information provided on these computer points is available on the graphics 25 computer scree Step 15d: The information provided by' all of the listed 0AC computer points is available .on the graphics 25 screen, along with the information required in step 15 Step 16, note: This note is actually a caution related to the performance of step 16. It lacks identification of the poten-tial hazard of seal failur ! Step 17: This step fails to identify the operating procedure required to accomplish the actions listed. An alternative to referencing the operating procedure is to specify the required i number of chillers to pumps for these action Step 19: This step includes reference to the NR system. This system is not in service at CNS and is not intended for any future us Step 25a, RNO: This step includes an overly complex layering of logic sequence Step 32, caution: This caution is actually an action step required within the procedure prior to performance of step 32.
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B-20 Step 32u: The list of valves included in this step is awkward and inconsistent with the placement of the ' valve switches on the
. control board . Step 33, caution: This caution is actually an action step required within the procedure prior to performance of step 3 . AP/1/A/5500/06 Loss of S/G feedwater No comments 9. AP/1/A/5500/07 Loss of normal power No comments 1 AP/1/A/5500/08 Malfunction of reactor coolant pumps Case II, step 6e: This step does not give guidance defining
" normal" for " lwr brg temp".
1 AP/1/A/5500/10 Reactor coolant leak- Step 1, caution: This caution lacks identification of the potential hazard and incorrectly includes use of the logic term WHE Step 5, note: This note is actually a conditional step required within the procedure prior to performance of step Step 8: The first bulleted item in the step incorrectly refer-ences OP/1/A/6200/02 with the title to OP/1/A/6100/02. The title is correct, however, the correct procedure number is the latte Enclosure 2, note 1: This note is actually an- action step required prior to performance of this enclosure, Enclosure 2, page 13, caution: This caution incorrectly contains a directive to the operato Enclosure 2, page 16, step 6a: This step references OP/2/6250/07A, Enclosure 4.3. A 35 foot extension ladder necessary to perform the procedural actions is dedicated for NE0 use at E33, TB-568. This ladder may be required for performance of the procedure enclosure. During the inspection walkthrough, the wrong type of ladder (12 foot step ladder) was found at the dedicated ladder locatio Enclosure 2, page 16, step 6al: This step fails to identify the required operating procedure enclosure number.
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I Enclosure 2, page 16, step 6a2 This step fails to identify the l required operating procedure enclosure numbe . Enclosure 2, page 19, step 1: "NC Pmp A (B,C,D) #2 Seal S-Pipe Hi/Lo Lvl" annunciator lights are removed as temporary modifi-cations during outages. However, these lights are referenced in this enclosure with no indication that they may not be availabl . AP/1/A/5500/11 Inadvertent NC system depressurization Case I, step C1, caution: This caution is actually a condi-tional step that applies during the performance of the entire procedure. Correct placement would be on a foldout page to the I procedur Case I, step 4, caution: This caution is actually a step that is required within the procedure prior to the performance of step Case I, step 5, caution: This caution is actually a step that is required within the procedure prior to the performance of step Case II, step C1, caution: This caution is actually a condi-tional step that applies during the performance of the entire procedure. Correct placement would be on a foldout page to the procedur Case III, step C1, caution: This caution is actually a condi-tional step that applies during the performance of the entire procedure. Correct placement would 'Je on a foldout page to the procedur . AP/1/A/5500/12 Loss of charging or letdown a. Case I, step C1, caution: See 11b abov Case I, step C3, caution: This caution fails to identify the potential hazard. In addition, it.contains a conditional stop that is required within the procedure prior to step Case I, step 01: See 7e abov Case I, step D2e, RNO: This step also requires a caution to address the consequences of exceeding 1 degree F per minute cooldown on any NV pump.
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e; Case I, step 6, caution: The first bulleted item in this caution is actually a step that is required within the procedure prior to performance of step 6. The second bulleted item is a caution, however, it fails to identify the potential hazar Case II, step C1, caution: See 11b abov Case II, step D1: See 7e abov . AP/1/A/5500/13 Boron dilution No comment 1 AP/1/A/5500/14 Control rod misaligned No comment 1 AP/1/A/5500/15 Rod control malfunction No comment 1 AP/1/A/5500/16 Malfunction of nuclear instrumentation system Case I, step 3c: This step directs , ensuring adequate shutdown margin but does not reference the procedure which is Lsed to accomplish thi Case III, step C.1: This step does not provide the setpoints associated with the parameters to determine if a reactor trip is require Case IV, step 2: This step directs monitoring nuclear instru-mentation but does not provide any actions to be taken if the listed conditions are not me . AP/1/A/5500/17 Loss of control room Communications between unit ASPS will be lost if PBX battery depletion renders the station dial phone system inoperativ Since the string phone circuits are unit unique and no radios are repositioned at or carried to the ASPS, there are no alternative communications option The procedure does not specify which of the two separate string phone circuit; -tauld be used for communications within a unit when the ASP or the SSF is activated. The walkthrough operator was not certain which was correc i
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B-23 c. Enclosure 1, step 1: During the walkthrough, the ASP operator was unable to simulate completion of this step because he lacked tools: to loosen the front panel bolts. Tools were available in a locked tool box in the AFWPTCP room but the ASP operator did not have the combinatio d. Contrary to instructions posted on the unit one ASP A panel access cover plate, the panel plate was unlocked, the cicsure bolts were removed and the access was ope e. Enclosure 1, step 6 RN0: This step neglects the case where one pump fails to start but the other is availabl The problem probably stems from the prohibited use of "and/or".
f. Enclosure 1, step 10 RNO a5: This double action statement should be split into two element g. Enclosure 1, step 10 b2c: The intent of this step is to reach and maintain ~25% PZR level . The RNO side accomplishes thi Due to the lack of an AER action verb, if level is already ~25%
the operator will continue without instruction to maintain level
~25%
h. Enclosure 1, step 11a: The results of the AER and RNO sides are differen The RNO side adjusts pressure to ~2235 psig and maintains it there. The AER side checks for pressure ~2235 psig and if satisfied continues without instruction to maintain that pressur . Enclosure 1, step 12: The use of " adequate normal" instead of just " normal" is confusing and unnecessar j. Enclosure 1, step 13 RNO 2: Delete typo ":" on line k. Enclosure 1, step 14: The team noted that the file of data book excerpts maintained at the ASP did not include the cooldown limits curv . Enclosure 1, ste, 29 and elsewhere within the E0Ps: Grammar; the two EPIP prccedures listed concern classification and notification, not just notification.
l m. Enclosure 1, step 23 and the preceding caution: The cooling l tower fans are no longer required beyond this step in the
! procedure. This step and the caution may be replaced by an action statement shutting down the fan l l
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B-24- Enclosure 3, step 3: Operation of the MODS under normal current load would blow. up the breaker cabinet. Although there are interlochs to prc<ent this and operators are trained on breaker /
MOD sequence of operation, the.EOP step is written with bullets indicating that sequence is not important. The step should provide a mandatory sequence and should be accompanied by an appropriate caution, Enclosure 3, step 5: The reciprocating charging pump for unit I has been tagged out of service awaiting repair since July 198 Two operators indicated that the positive displacement NV pumps on both units have.been difficult to maintain. If this service were typical for these pumps, their unavailability would ad-veesely impact the E0P Licensee management assured the team at the exit that the availability of these pumps is improvin Enclosure 7, step 4 RNO 1: Use of "out-of-specification" is confusing since the specification is not directly identified nor is it conventional to describe a containment 3 psig ESF signal as containment "out-of-specification" 19. AP/1/A/5500/18 High activity in reactor coolant No comments 20. AP/1/A/5500/19 Loss of residual heat removal Case I, step C1, note 1: This note is overly detailed. It is actually an action step that is required prior to step 0 Case I, step D8e, caution: This caution is actually a note, as well as an action step that is required prior to performance of step 08 Case I, step D9, caution: See 20b abov Case I, step D11f: This step fails to identify the necessary enclosure to the operating procedure reference In addition, only a limited number of the valves listed in the operating procedure enclosure are applicable in this case, Case II, step C1, note 1: See 20a abov Case II, step D3, caution: This caution is actually a note, however, it does not apply to performance of step D Case III, step C1, note 1: See 20a above, Faclosure 2, step A, caution: This caution contains an action step that is required within the procedure prior to performance of step C.
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i '. Enclosure 5,fstep A, note: This note is actually an action step that.is~ required prior to performance of step ' Enclosure 5, step A3, caution: .This caution fails to identify
'the potential. hazard. In addition, it contains an action step
~
required within the procedure prior to performance ~ of step. A . AP/1/A/5500/21 Loss of component cooling Step 3, RNO a.2: The valves required to be shut by this step do not have locations listed. Due to the fact that these valves are not located in proximity to the equipment being isolated an operator would have difficulty closing these -valves' in a timely manne . AP/1/A/5500/23 Loss of condenser vacuum No comment
. 2 AP/1/A/5500/24 Loss of containment integrity
- Section B,' case II: This section has multiple possible meanings between the second and third bulleted items due to the combined use of logic terms AND and O Case I,. step D2a: The four hour time frame indicated in .this -
step is in conflict with Tech. Spec. 3.6.1.1 LCO which indicates-that containment integrity must be restored within one hour. A justification for the basis of this conflict is require . - AP/1/A/5500/25 Damaged spent fuel Case 1, step'c2-4: This equipment is infrequently operated and the walkthrough NE0 had difficulty locating i It's location is not specifie Case 1, step d3 and elsewhere'in other procedures: This step requires ensuring containment integrity; the technical specifi-cation reference applies to all penetrations. The walkthrough operators were uncertain of which of several alternative methods of ensuring integrity applie . AP/1/A/5500/26 Loss of refueling canal or spent fuel pool level Incident to the walkthrough, the team inspected alarm response procedure IAD-13 E2 which listed minimum fuel pool level as 3 ft., the alarm setpoint, and referenced technical specification 3.9.1 The tech spet requires a minimum of 23 ft. of water above the top of the fuel. This equates to a level of 36.923 f .
u-mmm_-_u_m_u.__m-_m _m_._m _ __m__m
- - . .. _ _ - - _ -
,
e
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. . .
. . ...
B-26 T;,e licensee indicated that tha cror had been identified previously and that procedure and alarm setpoint changes were being held in abeyance pending results of a study concerning tech spec applicability and compliance in the event of a damaged, jammed or cocked assembly in the poo The daily surveillance procedure minimum level was 37.6 ft.
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APPENDIX C WRITER'S GUIDE COMMENTS This appendix contains writer's guide and human factors comments, observations and suggestions for E0P improvements made by the team. Unless specifically stated, these comments are not regulatory requirements. However, the licensee agreed in each case to evaluate the comment and take appropriate ectio These items will be reviewed during a future ' NRC inspection as notea i paragraph I. Deviations from the Writer's Guide A sample of the E0Ps and AOPs were evaluated for deviations from the Catawba writer's guide. Types of deviations noted are characterized in this section and accompanied by a list of examples of the specific devia-tion Note that some steps contain more than one exampl . The following steps violate writer's guide directions for the structure of logic statements:
EP/1/A/5000/1C 5 RNO 8 RNO EP/1/A/5000/1C2 33 EP/1/A/5000/1E2 2
6 RNO EP/1/A/5000/2C2 10 EP/1/A/5000/2E1 5 EP/1/A/5000/2E2 3 AP/1/A/5500/05 D4
D7 RNO D12 013 D22 RNO D25 RNO D34 D30 D35 RNO AP/1/A/5500/10 D4 l D8 l
AP/1/A/5500/12 Case I C3 RNO 02 RNO D6 Case II D2 RNO D4 RNO

\
r
:

. .
.-
.. <
C-2 AP/1/A/5500/19 Case I D7 D10 D]1 RNO D14 D14 RNO Case II D2 D2 RNO 1 l
D6 D8 Case III D15 RNO AP/1/A/5500/24 Section B Case I Case II Case I D1 D2 D3 Case II C1 The team reviewed 10 A0Ps for compliance to the writer's guid Generally, in the AOPs reviewed where the conjunctions "and" and
"or" were used, they were f.ormatted as if they were being used as logic term . The - following steps violate writer's guide directions for the structure of transition steps:
EP/1/A/5000/1C 14
EP/1/A/5000/1C2 18 RNO 25 RNO 33 RNO EP/1/A/5000/2E1 13 AP/1/A/5500/05 C1 RNO D1 i D2 RNO D5 RNO D7 RNO D13 D20 RNO D23 RNO I D25 RNO >
D27 D27 RNO D28 RNO DhD D31 D32 D34 D35 D35 RNO
. _ - _ _ _ _ _ _-
, - - _ - _ - _ . - .. _ _ __ _ _ . . _ _
.
. .
1 .
C-3
- AP/1/A/5500/10 01 RNO D3 RNO D4 D5 RNO D6 D6 RNO D7 D8 AP/1/A/5500/ Case ' D6 Case III D5
.AP/1/A/5500/12 Case I C3 RNO D5 RNO
D8 D9 Case II D2 RNO D4 RNO D5 RNO D7 D9 DIO D11 AP/1/A/5500/19 Case I D1 D4 RNO D5 D7 D8 D8 RNO
D11 D11 RNO D12 013 D14 RNO Case II D2 RNO D3 RNO D4
Case III D1 RNO -
D2 RNO D4 D5 D7 D11 RNO D12 D13 D14 D15
- - _ _ _ . - _ _ _ _. _ _ _
- _ _ _ _ - _ _ _ . _ _ - _-__ _ _ _ ._ ._ __ ___ - _ - -
.
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C-4 i
AP/1/A/5500/24 Section B Case I-Case I D1 D2 D4 RNO Case II D1 02 The many deviations from the writer's guide in the structure of and use of cautions and notes is described in appendix B of this repor . The writer's guide defines a format for presenting plant expected responses. The following steps do not use the defined format for expected responses:
EP/1/A/5000/1C 3
8
20 20 RNO
EP/1/A/5000/1C2 11
20
EP/1/A/5000/2E1 10 EP/1/A/5000/2F2 1 The team reviewed 10 AOPs for compliance to the writer's guid Almost every expected response listed in the .AOPs reviewed was formatted incorrectl . The writer's guide states that common English grammar should be applied within the procedures and that the verb is the most important word in an action step. The following steps lack a verb:
EP/1/A/5000/1C 1
4 RNO 5 RNO
9 9 RNO
15 RNO
23 RNO
27 RNO
- .. - - - _ _ -
_ _ _ - .. - . _ -
.,
-
3.:
.'e e-
.'., . . .
C-5 EP/1/A/5000/102 4
5 RNO
9 RNO
12.RNO
30-EP/1/A/5000/IE2 5 RNO 9 RNO
EP/1/A/5000/2C2 9 EP/1/A/5000/2C4 3 EP/1/A/5000/2E1 1 8 RNO AP/1/A/5500/05 C2 RNO D2
D5 D6
'D7 DIO D15 D23 RNO D24 D25 D28 D34 D35 D35 RNO AP/1/A/5500/10 D1 RNO D2 RNO i D5 RNO D8'
I AP/1/A/5500/11 Case I D1 RNO D3 D6 Case II C1 RNO D1 RNO Case III C1 RNO l D1 RNO l D3 RNO
__ _ _ _ _ - _ _ _ _ _ - _ _ _ .
_ _ _ _ _ _ . _ _ _ _ _ - _ _ -
_ _ _ _ _ _ _ _ _ _ _ _ _ -
.
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C-6 l' AP/1/A/5500/12 Case I D2 D2 RNO D3 RNO Case II C2 D1 D4 l
AP/1/A/5500/19 Case I D6 D8 08 RNO
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Case III D8 D11 D12 AP/1/5500/24 Case I D1 Case II C1 6. The following steps lack a subject:
EP/1/A/5000/1C 2 RNO EP/1/A/5000/102 34 AP/1/A/5500/05 D15 RNO D22 RNO AP/1/A/5500/12 Case II D2 RNO 7. Location information for annunciator lights was missing or incomplete in a number of procedures. The following examples lack either panel number or grid location number:
EP/1/A/5000/1C 22 EP/1/A/5000/2C4 3 3 RNO AP/1/A/5500/02 D1 AP/1/A/5500/02 C1 DS AP/1/A/5500/11 A

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_ _ _ _ _ _ _ _ _ _ _ _ _ _ _
. _ _ _ . __ ._ -. __ _ _ _ _ _ _ _ _ _ _ _
_- _ _ . _
- _ _
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C-7 The writer's guide. indicates that procedure nomenclature that exactl replicate; plant labels'should be set off by quotation mark Th following steps use quotation marks for nomenclature that does not exactly match that in the control room and plant:
EP/1/A/5000/1C 2
-
7
17
22 ,
23 RNO EP/1/A/5000/IC2 1
7
33 EP/1/A/5000/IC4 2 EP/1/A/5000/2C4 2
EP/1/A/5000/2E1 8 The following steps contain lists of valves that'are not arranged in an order consistent with their placement on the control board:
EP/1/A/5000/2E2 2 AP/1/A/5500/05 3 10. Appendix 5 to .the writer's guide states that a colon should be used to indicate substeps or that a list follow The following procedure steps lacked use of a colon in this manner:
EP/1/A/5000/1C 1
5 RNO 7'
9 14 1
l 17
'
20 RNO ;
l
_ - _ - _ _
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$- ....
', C-8
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s 24
1 27 EP/1/A/5000/ ICE 1-
4
'
6 RNO
9
11
14
17
20
22
2A
26
28
31
'
EP/1/A/5000/104 1
EP/1/A/5000/1C6 1
'
3
EP/1/A/5000/IE2 3
5
9
EP/1/A/5000/2C2 3
7
9 l
l l
_ - _ _ - _ .
_ _ _ _ _ _ . . _ _ . . _
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. .
.. ..
C-9 EP/1/A/5000/2C4 2
EP/1/A/5000/2E1 3
10
EP/1/A/5000/2E2 2 EP/1/A/5000/2F2 2
4
AP/1/A/5500/05 D7 D8 D24 D29 AP/1/A/5500/19 Case I D4 Case II D2 D3 D4 Case III D3 D6 D10 D11 D12 11. The writer's guide states that all steps should be written in active voice. The following steps are written in passive voice:
EP/1/A/5000/1C 4c RNO
II.-Inadequacies in the Writer's Guide In order to assure consistency within and between procedures and to retain that consistency over time and through personnel changes, the writer's guide must thoroughly address each aspect of the procedures and must define restrictively the methods designated for use.
The Catawba writer's guide contains a number of areas where lack of restrictive or thorough guidance has led to problems and inconsistencies in the E0Ps and AOPs. These weaknesses are as follows:
1: The writer's guide describes a structure for consequential steps l that combines a transition forward and a "WHEN condition X, THEN l
transition backward in the procedure." This system is overly com-plex. It is difficult to perform and provides no method of reminding the operator to transition backward to the original ste _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ . -_ __ _
__ . _ _ _ _ _ . - - - - - - . _ _ _ - _ . - - _ --_
4'
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'2, The guidance on preparation of notes and cautions improperly allows-
.the use,of logic-sequences in these statement . The instructions for use of "and" and "or" asi conjunctions directs -
a use of these terms when unnecessary, thereby contributing to confus- -
ing and overly complex action step . The writer's guide allows. the use of the logic term "if" as part of other sentences (for example, " check if"Jand " determine . if"). These forms dilute the usefulness of logic' statement structure and could .
lead to confusio .' The~ description of procedure substep numbering, bulleting and inden--
tation described in the writer's guide does not provide adequate guidance. As -a result, the procedures contain numerous examples of duplicate step numbering and steps where the relationship between a step and.its RNO step is not clea . 'The guidance on structure of subs'teps does not adequately define the difference between substeps as action steps and substeps. as list ~ It allows inconsistent use of complete sentences and incomplete sentence . The peacekeeping space system defined by the writer's guide provides checkoff' spaces at high level steps and in sequences of'four or more
-
. bulleted substeps. When a step includes several pages of substeps, this method does not provide ahquate peacekeeping and it requires operators to turn- backwards in the procedure to find the checkoff-mar The ' system also also. lacks sufficient peacekeeping for lists of control . The writer's guide states that procedure steps should have one ' main action and that multiple actions with a step are to be avoide However, numerous examples of multiple actions with steps were foun . .The writer's guide does not adequately address nor require some method 'of reminder to operators of steps that may be performed at some time in the future (e.g. , "WHEN condition, THEN action" sequences).
1 The writer's guide allows the listing of partial valve numbers in a horizontal list following one complete valve number. This method is s unsatisfactory. It circumvents the writer's guide method for place-keeping and increases the possibility of error or confusio . The writer's guide defines the transition tern REFER T0" as indi-cating that an operator will leave his place in the procedure to go elsewhere, and then later return. This is in contrast to the PSTG definition and the common definition of " REFER T0" as indicating concurrent execution of step _ _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ - _ _ _ - - _ _ _ _ _ _ - _ _ _ _ _ _ - - - _ - _ _ - _ _ _ _ -
-- _
- -_ - -- _. - _ - _ _ _ _ _ _ . _ _ - . _ _ _ _ _ - _ .

,.
. '.* .
C-11 1 The ' dictionary of acronyms and abbreviations in the writer's ' guide lists a number of abbreviations for which there are two definitions and a number of definitions for which there are two acronyms or abbreviation Elimination of all dual use or dual definition entries is necessar . The constrained language list in the writer's guide contains a number of words that have the same meaning and others that ciffer only-slightly in meanin Elimination of multiple approved vocabulary having the same meaning will increase ease of procedure comprehension and clarify distinctions between those words that are similar but differen . The writer's guide fails to describe a method for indicating possible plural status. For example, as in the step " check faulted S/Gs."
1 Enclosures to procedures must be subject to defined structure in the writer's guide. The Catawba writer's guide dismisses enclosures from the restrictions used'in procedure . The use of the symbol for "approximately" is allowed by the writer's guid Directions that prohibit use of this symbol and require the use of bounded tnierances whenever possible are not included in the writer's guide.
! !
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APPENDIX D-NOMENCLATURE
This appendix contains team observations of cases where E0P and panel nomenclature differ The licensee agreed in each case to evaluate the difference and make the appropriate change. These items will be reviewed during a future.NRC inspection as noted in paragraph Procedure Step /p E0P Nomenclature Component Nomenclature EP/1/A/5000/1A 5. "S/V BEFORE SEAT "S/V BEFORE SEAT DR" DRN CLOSE" "C LOS E
EP/1/A/5000/1A 1 VCT FWST EP/1/A/5000/1B 29/25 1-RF457 1-RF457B EP/1/A/5000/1C 24/15 -1NI-178B (ND Hdr IB To ND HEADER 18 TO NC Cold Legs A & B) COLD LEG LOOPS C&D VALVE INI-178B INI-173 (ND Hdr IA To ND HEADER 1A TO NC Cold Legs C & D) COLD LEG LOOPS A&B VALVE INI-173A 4/4 INI-334B (NI Pump Suct SAFETY ING. PUMP X-0VER From ND) SUCT X0VER FROM EP/1/A/5000/103 4 1EDE-F01F No label EP/1/A/5000/2A Enclosure 1 1 1CA-185 LETTER SIZE IS SMALLER THAN THE REST OF THE LABELS-EP/1/A/5000/2C4 3/3 1CDB-F0IC ICDB (nc breaker cubicle label)
ICDA-F08H ICDA (no breaker cubicle label)
EP/1/A/5000/2C5 2 IBB69 No label EP/1/A/5000/2d3 14/7 multiple "... T/V SS ... T/V Ss RESET ... ,
RESET" AP/1/A/5500/02 C4a2 RNO STM PRESS PRESS D2 CF HDR PRESS S/G INLT HDR PRESS
)
- - _ _ _ - _ .. - -
. _ - _ _ _ ____- __ -
. ,
y .
=
D-2 Procedure ' Step /p E0P Nomenclature Component Nomenclature AP/1/A/5500/03 C1,2 RNO CF HDR PRESS S/G INLT HDR PRESS D17 R-L RAISE-LCYER I I
D19d SWITCH NOT ON THE CONTROL j BOARD {
AP/1/A/5500/04 2a Temp defeat Delta temp defeat AP/1/A/5500/08 II, AD-17 1AD-7 II,0.4b Chg Hdr Flow Chg Ln Flow AP/1/A/5500/13 C2 & RNO CONTROL R00 BANK IS THE WRONG NAME FOR LO-LO LIMIT FOR COMPUTER POINT D4409 C2 BORIC ACID XFR PMP B/A XFER PMP AP/1/A/5500/17 Encl. 1- b2/11 Chemical letdown ... xNVP5531 LETDN ...
l
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13/1 Blackout accident B/0 SEQ activated sequencer activated Encl. 6 4/2 ISGR-D-1, -3 Does not exist
4RN0/2 ISGR-D-2, -4 Does not exist Encl. 7 4/3 Containment pressure Applicable meters have inst. ids and noun; latter do not include any ref. to containment pressure.
i AP/1/A/5500/25 3e/1 Refueling bridge Reactor b1dg refueling 3b/1 reactor bldg ... bridge
&
cl/2 d1/3 vp trn a upr cent vlvs ... pushbutton ...
enable switch ...
l 'vp trn b upr cont vlvs ... pushbutton ...
! enable switch l
l
!
L__ _ ___ = - _ - - - - _
.. _ _ . . _ _ - - __
_ _ _ - _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ - _ _ - _ - _ _ _ _ - _ _ _ _ _ _ _ _ -
..

.. .. ,
u ..
D-3 Procedur Step /p E0P Nomenclature Component Nomenclature AP/1/A/5500/26 b/1 IEMF-15 refueling spent fuel bldg bridge spent fuel bldg refueling bridge ...
AP/1/A/5500/26 d1/3 vp trn a upr ... cont ... P/B ...
vivs enable switch ... block ...
"close"
... lwr cont vivs switch ... key switch ...
"close" . . . b1 k cl sd . . .
.. vp tr a enable ... keyswitch ...
pushbutton "close" ... block ...
vp tr b upr cont vivs ... P/B ...
enable switch "close" ... block ...
vp tr b lwr cont enable ... key switch ...
switch "close" ... bik cisd ...
OP/1/A/6450/10 2/3 -1ELCP0025 IELCP0251 e__________-____--
_ __ .
-
a
. . . ,
sl 9 h APPENDIX E l LIST OF ABBREVIATIONS
AC Alternating current AER Actions / expected response A0 Auxiliary operator A0P Abnormal operating procedure AP Administrative procedure ASP Auxiliary Shutdown Panel CA Auxiliary Feedwater System CFR Code of Federal Regulation CLA Cold leg accumulator CMD' Construction and modifications division CN Catawba Nuclear CNS Catawba Nuclear Station CNSD Catawba Nuclear Station Directive CSF Critical Safety Function CST Condensate Storage Tank DPCPDPR Duke Power Company Procedure Discrepancy Process Record D/G Uiesel generator DHP Dynamic head pressure D/ Differential pressure DRS Division of Reactor Safety ECA Emergency contingency action ECCS Emergency Core Cooling System E0P Emergency operating procedure l EPIP Emergency plan implementing procedures EPRI Electric Power Research Institute ERG Westinghouse emergency response guidelines ESF Engineering Safety Features ETQS Employee training and qualification system FSAR Final Safety Analysis Report FWST Fueling Water Storage Tank GPM Gallons per minute GTG Generic technical guidelines HP Health physics IAE Instrument and electrical IEEE Institute of Electrical and Electronic Engineers IEN Inspection and Enforcement Notice IFI Inspector Follow-up Item IN Information Notice INPO Institute for Nuclear Power Operations KC Component Cooling Water System KF Spent Fuel Coeling System LCO Limiting Condition for Operation LER Licensee Event Aeport LOCA Loss of Coolant Accident MOD Motor operated disconnects MSIV Main steam isolation valve MWR Maintenance Work Request
!
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. _ . - . _ _ _ _ _. . _ - _ =- . _ - _ _ - _____ -___--_-_-_._____ _ ___ ___- - - - _
- _ , -
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a[s A'
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E-2:
,
NE0 Nuclear equipment operator NI Nuclear Instruments NRC Nuclear Regulatory Commission NS . Containment Spray System NSM_ Nuclear Station Modification NSMM' Nuclear Station Modification Manual NUREG Nuclear Regulatory Commission NV Chemical Volume and Control System OAC Operator aid computer OP Operating procedure
< 0STI Operational Safety Team Inspection PGP Procedure generation package PIR Problem Identification Report PM Preventative maintenance POR Power operated relief valve PPM Parts per millfon PRT Pressurizer relief tank PSIG Pounds per square itich gage PSTG Plant specific technical guidelines PT Performance test PWR Pressurized Water Reactor PZR Pressurizer QA Quality assurance RCS Reactor Coolant System RN Nuclear Service Water System RNO Response not obtained R0 Reactor operator R&R Removal and restoration SALP Systematic Assessment of Licensee Performance SER Safety evaluation report S/G Steam generator S/G TR Steam generator tube rupture S/I Safety injection SME Safe Margin Earthquake SNSWP Station Nuclear Service Water Pond SPD .Setpoint document SRO Senior reactor operator SS Shift supervisor SSE Safe Shutdown Earthquake SSF Safe shutdown facility SWR Standing work request TS Technical Specifications TSM Temporary Station Modification UST Upper Storage Tank VAC Volts alternating current VCT Volume Control Tank V&V Validation and verification WR Work request
- _ _ - - _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ - _ _ _ _ - - _ _ _ - _ - _ - _ _ - - _ _ _ _ - - ___-_ ___-- _____ ________ _-__ _ _ - _ _ - _ _ - _ _ _ _ _ - _ .

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1989 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 8(0) 9(0) 10(0) 11(0) 12(0) 13(0) 14(0) 15(0) 16(0) 17(0) 18(0) 19(0) 20(0) 22(0) 23(0) 24(0) 25(0) 26(0) 28(0) 19(0) Security Operator Exams Emergency Planning Other

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