ML20203L570

Safety Evaluation Supporting Proposed Tech Specs Re Alternative Shutdown Sys.Acceptability Based,In Part,On Performance of Tests in Accordance W/Reg Guide 1.68, Initial Test Programs for Water-Cooled Nuclear Plants

ML20203L570
Person / Time
Site:	Fermi
Issue date:	08/19/1986
From:	Office of Nuclear Reactor Regulation
To:
Shared Package
ML20203L525	List: ML20203L523 ML20203L570
References
RTR-REGGD-01.068, RTR-REGGD-1.068 NUDOCS 8608280041
Download: ML20203L570 (3)

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{{#Wiki_filter:. . EFCLOSURE 1 [ o DPAFT EFETY EVALUATION BY THE OFFICE OF NUCLEAR REACT 0P REGULATION RELATING TO ALTERNATIVE SHUTDOVN SYSTEM FERMI-? DOCKET NO. 50-341

1.0 INTRODUCTION

In the Safety Evaluation Report (SER) issued in July 1981, and in Supplement No. 2 to the SER, the NRC staff found the licensee's procram for fire pro-tection at the Fermi-2 f acility to be acceptable. However, followino a site audit of fire protection in May 1984, the staff found that the licensee had not provided fire protection for the control room in accordance with its commitments. The staff also found durina this site audit that the senar-ation between redundant, safety-related electrical divisions in the relay room was unacceptable. Fol10 wine an intensive review of en alternate shut-down capability independent of the control room, the cable spreadinn room and the relay room, the staff's reevaluation of the Fermi-2 fire protection program was presented in Appendix E of Supplement No. 5 to the SER (SSER No.

5) in which the licensee's system for shutting down the facility in the event of a ma,ior fire, was found to be acceptable. The NRC staff conditioner' the low power license (NPF-33Y issued in March 1985, to reflect the licensee's commitment to install the independent, alternate shutdown panel no later than December 31, 1986. Subsequently, in licht of numerous concerns reoerding the need for an earlier implementation of the independent, alternate shutdown systen, the staff conditioned the full power license (NPF-43) issued in July 1985, to require installation and operability of the independent, alternate shutdown system no later that October 30, 1985. The plant was shutdown on October 11, 1985, to install the dedicated control panel, some-times referred to as the 3L panel, and some other safety-related equipment.

As part of its commitment on this matter, the licensee submitted proposed technical specifications for the Alternative Shutdown System (3L ranel) in its letter dated September ?7, 1985. This submittal was later supplemented in the licensee's letter dated July 15, 1986. These technical specifications for the 3L panel are to be added to the Fermi-? Technical Specifications as new sections 3/4.3.10, P 3/4.3.10, 3/a.7.4, and B 3/4.7.9. 2.0 EVALUATION In its initial review of the licensee's September 27, 1985, submittal, the staff expressed concerns regardino the licensee's pronosed surveillance intervals. In response to these concerns, by letter dated July 15, 1986, the licensee resubmitted its proposed technical specifications to provide a more restrictive action statement reaarding inoperability of the Combustion Turbine Gererator (CTG) and more frequent testino of the Standby Feedwater System as well as to provide clarifyino information. 8608280041 DR 860819 ADOCK 05000341 PDR

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-                                       -E-Technical Specifications 3/4.3.10 address the instrumentation associated with the independent, alternate shutdown system. This instrumentation includes the indications of the reactor water level, reactor pressure, standby feedwater flow, condensate s torage tank water level, torus water temperature, torus water level, and the primary containment temperature.

Tne power for the dedicated shutdown system is provided by the one of the onsite combustion turbine cenerators (CTG). The instrumentation provided for the CTG provides indication of the output voltace, frequency, and power level. Control circuits have been provided for controlling the CTG, the standby feedwater system (SBFWS), residual heat removal (RHR) system "C", the RHR heat exchanger "A", Division I of the emergency equioment cooling water (EECW1 system, and the coolers for the drywell. The proposed technical specifications require that the Channel Check be performed monthly and that the Channel Calibration be performed during refueling, every 550 days (18 months). This reouirement is consistent with similar technical specifi-cations for other instrumentation which is safety-related or important to safety and includes the instrunentation identified in SSER No. 5. Accordingly, these proposed Technical Specifications are acceptable. Technical Specifications 3/4.7.9 concern the operability of the SRFWS, the CTG and the drywell cooline units. The SRFWS and the drywell cooling units have a seven day inoperability limit in the proposed Technical Specifications which is consistent with the Standard Technical Specification limits. The licensee has proposed an inoperability limit of seven days for the CTG, the power supnly for the independent alternate shutdown system, or an alternate power supcly is ;c be provided within 14 days, or the reactor is to be in hot shutdown within the next 12 hours and in cold shut-down within the followino 74 hours. These limits poverning the time period when the CTG may .be inoperable are generally consistent with similar tech-nical specifications for dedicated shutdown panels for fire protection except for the time period for securing an alternate power supply, The basis for these inoperability limits is contained in the licensee's sub-nittal dated July 15, 1986, in which the licensee states that there are three additional onsite CTGs which could be used to provide power to the alternative shutdown system. An alternate source of power is defined as one which does not rely on offsite power for: (1) starting, if required; or (21 operating, if already runnino. It is also capable of supplyino the required loads associated with the alternative shutdown system. The licensee states, and the NRC staff agrees, that the three other onsite CTGs meet these criteria. On this basis, we conclude that it is ecceptable to permit the licensee to have an additional seven days beyond the nonnally acceptable inoperability limit of seven days (i.e., a total of 14 daysi to provide an alternate power source because of the Fermi-? plant unicue features (i.e., the four onsite CTGs1

       .   -                                                                          DRAFT r
   .                                                         The licensee proposes surveillance reouirements which reauire the licensee to demonstrate every 31 days that the CTG is operable. This is in confor-mance with the Standard Technical Specification surveillance frequency and is, therefore, acceptable. There are two SBFWS pumps and two drywell coolers.

Either S8FWS pump can supply all the reouired water for achieving a safe shutdown and either non safety-related drywell cooler is capable of provid-ing adequate cooling. Accordinoly, the licensee has proposed to demonstrate that the SRFWS oump is operable every 31 days on a staggered test basis and to demonstrate one of the drywell coolers to be operable every 31 days.

         . Since there is redundancy in the SRFWS pumps, testing one of these every 3) days on a staggered test basis will ensure that in the event of a fire, one of the SBFWS_ pumps will have been tested within the previous 31 days. There-fore, we conclude that the testing of the SBFWS pumps and the drywell cooling units every 31 days on a staggered test basis, is acceptable.

The acceptabi.lity of the proposed technical specifications is based, in part, on the licensee performing a successful test of the alternative shut-down system and related procedures in accordance with the guidelines of Regulatory Guide 1.68, " Initial Test Programs for Water-cooled Nuclear Power Plant," a,s committed to by the licensee in the Fermi-2 FSAP, or an acceptable alternative thereto. Pepion III will verify the adequacy of the system testino for the alternative shutdown system. On the basis of the proposed technical specifications for the alternative safe shutdown systems, their consistency with similar technical specifica-tions, plant ' specific emergency power supply capabilities, and the accept-ance of the alternative shutdown system test by Region III, the NRC staff concludes that the proposed technical specifications are acceptable. O i k t -

ENCLOSURE 2 e

                                                             \

l U.S. NUCLEAR REGULATORY COMMISSION ' REGION 1i Report No. 50-352/85-37 Docket No. 50-352 License No. NPF-39 Priority - Category C Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Penn ylvania 19101 Facility Name: Limerick Nuclear Generating Station Inspection At: Limerick, Pennsylvania Inspection Conducted: Septem_ber 3-20, 1985 Inspectors: (( [O ) ' i tats

                       %Florek tpa -React r Engineer G ' / />3                                  A/h/dd a te
                                                                                               ~

D. C ht 15eni r Technical Reviewer f . /f))l fn /0//pfff Re tor Engineer at S .#

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                            }K charYskifu          hn :

P fli s set't , Reactor Engineer da'te Approved b : 7 scszt /////[/_'[

                                                                                ~ date
                      # F. Eselgroth/phief, Test Program Section Inspection Summary:

Inspection on September 3-20, 1985 (Inspection Report No. 50-352/85-37) Areas Inspected: Routine, onsite unannounced inspection of the startup program during test condition TC-2 including startup test witnessing of the major startup tests, shutdown from outside the' control room and loss of offsite power and startup test results evaluation; licensee action on previous inspection findings; QA/QC interfaces; independent measurements, calculations and verifications; and tours of the facility. The inspection involved 145 hours by four region-based inspectors. Results: No violations were identified. ha M$ " 52 g rt o 9 09 T w.....,. .

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t-6 to the test. As expected, the reactor did not trip during this test. The inspector observed that less than 7 turbineAt bypass valves the 0020 hours, were required to open following the turbine trip.No unacceptable conditions turbine generator was back on the grid. were noted. On September 11, 1985 at 1500 hours, the licensee conducted STP-28.2. The plant was already in shutdown due to an unanticipated reactorThis test req scram that occurred earlier in the day. plant from 150 psig reactor pressure, cooling down, placing the shut-down cooling system in service and lowering reactor temperature by 50*F, all from the remote shutdown panel. At 1150 hours on September 11, 1985, the licensee began cooling down from 500 psig reactor pressure by use of RCIC in the condensate stor-At 1327 age tank (CST) to CST flowpath and by opening steam drains. hours, the RCIC turbine tripped due to high indicated water (+54"). At the lower pres-sensors indicated water level in the normal range. When this sures, wide range and narrow range have large differences. occurred, the licensee also noted that reactor water level on the remote shutdown panel also utilized wide range level and was pegged high. The licensee noted this difference and for this test. stationed the shift technical advisor in the auxiliary RCIC equipment room operation to pro-from the re-vide the narrow range level information. mote shutdown panel is not affected by the high water level indication since the high level RCIC turbine trip is bypassed when the remote shutdown panel is utilized. The licensee further did not want to utilize the remote shutdown panel wide range level indication to con-trol level in the normal indicated range since, for this test, this level would initiate the reactor protection low water level trips. During a situation which requires remote shutdown, however, this would not present a problem. RCIC was operated The remote shutdown panel was manned at 1500 hours. The licensee and SRV actuation was utilized to cool down the plant. also had the required operating crew in the control room to monitor plant performance and te take over control, if the remote shutdownR After panel was unable to do so. injection and then was transferred to the CST several SRV lifts to cooldown, vessel inventory required replenishment to restore water level; the only other source of water during this evolution was "from the control rod drive (CRD) system (~50 gpm). RCIC was being realigned to tra,nsYer water from the CST to the vessel; however, the injection valve could not be opened from the remote shut-down panel. The licenste attempted to operate the valve locally but was unable to do so. The licensee evaluated the situation and secured the RCIC from CST to CST operation and attempted to open the valve manually. The licensee was able to manually open the valve suf-ficiently to allow the remote operator to open it the rest of the way. During this period, flow from the CRD system restored normal level

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  .                                         7 without any need for RCIC. The licensee then jointly operated RCIC in the vessel injection mode and SRV to cooldown to the point at which shutdown cooling could be placed in service. This was accom-plished and a 50'F cooldown was demonstrated. The test was then ter-minated and control was restored to the control room at 1935 hours.

Throughout the test, the licensee was very thorough in assuring that information on plant status in the remote shutdown areas was obtained from instrumentation outside the control room only. The test demon-strated that the plant can be cooled down and placed in shutdown cool-ing from the remote shutdown panel and also demonstrated modifications to the procedures and remote shutdown panel area to enhance the abili-ty to shutdown from the remote shutdown panel. In-luded are the water level indications, key control provisions, need for P&ID's in the remote shutdown area and minor sequence changes in the procedure. The licensee was recording these observations as they occurred and i the licensee planned to address them. The inspector will review the licensee actions in a future inspection. On September 12, 1595, the licensee performed a reactor scram and MSIV isolation and began a controlled reactor cooldown, as described in STP-28.1, from the remote shutdown areas. The control room was evacuated at 1842 and reactor scram occurred at 1844. All control rods were inserted. The reactor cooldown was initiated at 1856 hours and terminated at 1932 hours and satisfied the test requirements. No unacceptable conditions were noted. On September 16, 1985, the licensee performed STP-31.1, " Loss of Tur-bine Generator ana Offsite Power." The reactor was at 20.8*. power prior to the test. Inspectors were stationed in the control room and at the diesel generators. After the start of all diesel generators, inspectors toured various elevations of the reactor and control build-ings for lighting levels. At 1752 hours, the test was initiated by a turbine trip and isolation of the offsite sources of power. Because the plant was within the bypass capacity and uses inverters for the R05 power supply, a reactor scram does not immediately occur. The j inspector observed diesel generator operation within 10 seconds. Be-l tween 5 and 6 bypass valves controlled reactor pressure. At approx-l imately 58 seconds into the event, the inspector observed a reactor I scram occurred on low level. All rods inserted. No safety relief valves were required to operate and bypass valves closed. At approx-l imately 23 minutes, High Pressure Coolant Injection (HPCI) auto ini-tiated on low level. Reactor Core Isolation Cooling (RCIC) was manu-ally started and HPCI secured to cortrol reactor cooldown. At approx-imately 25 minutes, the Main Steam Isolation Valves (MSIV) automati-cally shut. The diesel generators were observed to run for the thirty minutes required in the procedure. During the plant tours conducted i during the loss of power test, two areas were noted wherein lighting levels were poor: 1) the 283 foot level near the hydrogen recombin-ers and the standby liquid control system and 2) the 313 foot level near the ventilation ducts. The licensee personnel were also

noe UNITE] STATES ENCLOSURE 3

       .                                  NUCLEAD RESULATORY COMMIS$10N 3
                            ,,'                        r EllON 11 o                  101 MARIETTA STREET.N.Q.

I ATLANTA, GEORGI A 30323 o, j

 *            +,       /                         July 25, 1986 Docket Nos. 50-413, 50-414 License Nos. NPF-35, NPF-48 Duke Power Company ATTN: Mr. H. B. Tucker, Vice President Nuclear Production Department 422 South Church Street Charlotte, NC 28242 Gentlemen:

SUBJECT:

NRC AUGMENTED INSPECTION TEAM REPORT N05. 50-413/86-25 AND 50-414/86-27 This refers to the Nuclear Regulatory Commission (NRC) augmented inspection conducted by hr. V. W. Panciera on June 28 - July 2, 1986. The inspection included a review of activities authorized for your Catawba facility. At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed inspection report. Areas examined during the' inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and rep _resentative records, interviews with personnel, and observation of activities in progress. The violations described in the enclosed Inspection Report are under considera-tion for escalated enforcement action. Accordingly, no Notice of Violation is being issued at this time, and no response to this letter is required. However, please be advised that the number and characterization of violations described in the enclosed Inspection Report may change as a result of further NRC review. You

     -   will be advised by separate correspondence of the results of our deliberations on this matter. Additionally, an enforcement conference will be scheduled for August 1986 in Atlanta.

! In accordance with Section 2.790 of the NRC's " Rules of Practice," Part 2, ! Title 10, Code of Federal Regulations, a copy of this letter and its enclosure will be placed in the NRC Publi: Document Room. Should you have any questions concerning this letter, please contact us. 1 Sincerely, O 1 0. E# J. Nelson Grace Regional Administrator

Enclosure:

(See page 2) l l l l l i

Duke Power Company 2 July 25, 1986

Enclosure:

Inspection Report cc w/ enc 1: R. L. Dick, Vice President - Construction J. W. Hampton, Station Manager e h 4

l l mee UNITEJ STATES O [ o -. NUCLEAR CEIULATZY COMMISSION CECION ll I

       $             0                       101 MARIETTA STREET.N.W.

• 3 ATLANT A. GEORGI A 30323

           % ,,,,,e'   .-

Report Nos.: 50-413/86-25 and 50-414/86-27 Licensee: Duke Power Company 422 South Church Street Charlotte, NC 28242 Docket Nos.. 50-413 and 50-414 License Nos.: NPF-35 and NPF-52 Facility Name: Catawba 1 and 2 Inspection Conducted: June 28 - July 2, 198E Inspectors: B. Wilson P. Burnett H. Christensen M. Thomas D. Hood C. Vanderniet K. VanDoorn M. Lesser G. Lapinsky

        ..             J. Mauck      ,,

Approved by: 62 4 Vincent W. Panciera,Geam Leader 2 ce b 2-Date Signed f

SUMMARY

Scope: This special, announced augmented inspection was conducted for the

  -   Catawba Unit 2 depressurization(event on June 27, 1986. The areas inspected tiicluded, the sequence of events, equipment failures, human factor deficiencies, thermo-hydraulic effects, system logic designs, training, and modification and procedural controls.

Results: Two violations were identified:

1. Violation (414/86-27-01) - Multiple examples of failure to establish, implement or maintain procedures, in accordance with Technical Specification 6.8.1.

a. Failure to review Design Change Authorization (DCA) CN-2-M-1527, in accordance with Design Engineering Procedure EDP-3.17, Control Room Changes - Handling.

b. Failure to adequately review shutdown requests in accordance with Station Directive 3.0.3, Management of Shutdown Request.

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2 c. OP/2/A/6100/04, was inadequate. Shutdown Outside the Control Room From Hot Standby, It established settings in the auxiliary shutdown panels and erroneous. auxiliary feedwater pump turbine control panel that were -

d. TP/2/A/2650/03, Loss of Control Room Functional Test, was inadequate, due to a lack of appropriate test termination criteria, which in turn led tocontrol plant a failure to initiate to the controlsafety room. injection promptly by returning  ;

e. Failure to implement Operations Management Procedure OMP l-6, Control panel Information Changes, when labeling 2NV-294 (charging pump discharge flow control valve) and 2NV-309 (seal water injection back pressure control valve) controllers located on Unit 2 auxiliary shutdown panels. 2. Violation (414/86-27-02) - tion training in accordance with Technical Specification 6.4.1. Failure to provid 4 _ _ _ _ - _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - ' - - ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

REPORT DETAILS

1. Persons Contacted Licensee Employees:

                    *J. Hampton, Station Manager
                   *H. Barron, Superintendent of Operations
                   *W. Bradly, Quality Assurance
                   *S. Brown, Reactor Engineer
                   *B.

Caudwell, Superintendent of Station Services

                   *J. Cox,   Superintendent of Technical Services
                   *M. Criminger, QA Surveillance Engineer
                  *T. Crawford, Integrated Schedule Engineer H. Davenport, Design Engineer B. Dobson, Design Engineer
                  *C. Hartzell, Ccmpliance Engineer
                  *A.
                  *C, Jackson, Integrated Schedule Support Engineer Jensen, Unit 2 Schedule Engineer
                  *P. LeRoy, Licensing Engineer
                 *F. Mack, Project Services Engineer S. Mattix, Design Engineer
                 *W.
                 *F. McCollum, Superintendent of Integrated Schedules Schiffley, Licensing Engineer
               ~*L. Schmid, General Of fice, Operations
                *R.

Sharpe, General Office, Licensing

                *G. Smith, Superintendent Maintenance P. White, Design Engineer i

Other licensee employees contacted included engineers, technicians,

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operators,~ mechanics, security office members and office personnel. NRC Resident Inspectors

               *P. Skinner, Senior Resident Inspector
               *K. VanDoorn, Senior Resident Inspector
               *M. Lesser, Resident Inspector

• Attended exit interview.

2. Exit Interview The inspection scope and findings were summarized on July 2, 1986 with those persons indicated in paragraph 1 above. The inspectors described the i areas inspected and discussed in detail the inspection findings listed below.

No dissenting comments were received from the licensee. l l

                    .            --                        g

• The licensee did not identify as proprietary any of the material provided to or reviewed by the inspectors during this inspection.

By a telephone call to the station manager on July 18, 1986, the licensee I was informed two violations had been identified. 3. Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspection.

4. Unresolved Items Unresolved items were not identified during the inspection.

5. Overview

a. Description of Transient At 9:41 a.m. on June 27, 1986 a Loss of Control Room Test was initiated on Catawba Unit 2 to fulfill one 6f the commitments for startup testing made in FSAR Table 14.2.12-2 page 32. A crew of five, simulating the minimum shift crew available to Unit 2 operations, started the test by leaving the control room, tripped the reactor from the trip breaker panel, and proceeded to the two remotely-located auxiliary shutdown panels (ASP), and the auxiliary feedwater pump turbine control panel (AFWPTCP). At the ASPS and AFWPTCP, switches were activated trans-ferring control of vital functions from the control room to the auxiliary panels. By design, the transfer blocked automatic initiation of safety injection (SI). By error, the transfer of control of steam generator (S/G) power operated relief valves (PORV) to the AFWPTCP also commanded all four PORVs to open to seventy-five percent of full

_ stroke. Reactor pressure and pressurizer level, which had been decreasing slowly as a result of the cooldown after the trip, fell rapidly. Within a minuto of the transfer, pressurizer level indication was lost, and within two more minutes pressure had dropped below 1845 psig generating a SI demand signal. After another three and one-half minutes of unsuccessful attempts to manage the situation from the ASPS and AFWPTCP, control was returned to the control room, which was staffed by the regular operations shift. The transfer, which automat 1-cally initiated SI, occurred at a pressure of 702 psig, the lowest pressure recorded. Safety injection was terminated about five minutes later,10:00 a.m., with reactor pressure above 1200 psig, pressurizer level near 34 percent, and about 100*F subcooling. At this point the operators had full control of the stabilized plant. Figure 1, which the licensee made available to the team soon after their arrival on site, shows the temporal relationship of pressurizer level and pressure throughout the transient. The figure was derived from computer-logged data, which were delogged in analog form after the event. The annotation was added by the licensee.

3

b. Contributing Causes of the Event The underlying cause of this event was the failure to specify in the DCA or other documents that the mode of control of the S/G PORV controllers at the AFWPTCP had been changed. This in turn led to a failure by station personnel to change procedures and train operators on this modification. The situation was further exacerbated by human engineering deficiencies introduced by the modifications. As a conse-quence, the staff assigned to perform the test did not understand the function and interaction of controls on the shutdown panels. This lack of understanding led to a pretest setup of the panels that ensured that the futile.

be PORVs would open on transfer and that attempts to shut them would Other human engineering factor failures led to reducing charging very attempts toflow pump and flow increase to the reactor coolant pump seals by the flow. Although the main control room PORV controllers were replaced with safety-related controllers, the licensee chose not to replace or modify the AFWPTCP controllers. (HED) was performed on the shutdown panels.Also, no human engineering d Other contributing factors to this event included inadequate training on the shutdown panel instruments and controls, inconsistencies in labeling of instruments and controls, lack of termination test criteria

           ^~

and reluctance by the control room crew to assist the shutdown panel crew for fear of invalidating the test.

c. Restart Effort A Confirmation of Action Letter was issued to Catawba Unit 2 on July 3, 1986.

In the letter the licensee management has agreed to develop a detailed restart plan which deals with the corrective actions necessary to correct deficiencies identified in the following areas: (1) HUMAN FACTORS (2) PROCEDURES (3) EQUIPMENT LABELING l (4) RETRAINING (5) EQUIPMENT REPAIR In addition, licensee management has agreed that " Loss of Control Room ! Functional Test" will be rerun after attaining the requisite power l rating to adequately demonstrate that the plant can be safely shut down and cooled down from the auxiliary shutdown station following evacua-1 tion of control room. l i I l l

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6. Sequence of Events

a. Chronology The following plant computer:detailed chronology of the event was obtained from the NOTE:

The three shutdown panels are located in the control building three levels below the main control room. They are desig-nated auxiliary shutdown panels A and B (2 ASP-A and 2 ASP-B) and the auxiliary feedwater pump turbine control panel (AFWPTCP). 2 ASP-A controls A train equipment and 2 ASP-B controls B train. The unit can be controlled and cooled down from either ASP and the AfNPTCP. 06/27/86 09:37 Commence TP/2/A/2650/03, Loss of Control Room Functional Test. Communications established between auxiliary shutdown panels and the main control room. 09:41:00 Operators dispatched, senior reactor operator (SRO) and balance of plant (BOP) operator to 2 ASP-A and 2 ASP-8, reactor operator (RO) to the reactor trip breakers.

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RCS Pressure 2235 psig Tc Loop C 553 F Th Loop C 567 F PZR Level 29 !s Charging 90 gpm Letdown 76 gpm

       ,        09:42:32 Reactor trip breakers 2A & 2B opened locally by RO who then proceded to AFWPTCP.

Turbine stop valves 1, 2, 3, & 4 closed. 09:42:59 Control transferred to 2 ASP-A. Charging flow drops to approxi-mately 39 gpm. Since letdown flow is approximately 76 gpm, pressurizer level begins to slowly decrease. pressure letdown control valve) fails open. 2NV-148 (low to show signs of flashing by wide oscillations in indicatedLetdown flow begins letdown flow. 2 -3 ( s m isolation valves 2A & 2C) close. Tc Loop C 554*F Th Loop C 562 F PZR Level 24 ;; , Charging 39 gpm Letdown 60-105 gpm (wide oscillations) s

               .        -: r                           5 09:43:02 25M-5 (main steam isolation valve 28) close.                           -

09:43:09 Control transfered to 2 ASP-B. 2SM-1 (main steam isolation valve 20) close. NOTE: Probable computer printout error for 2SM-5 because 2SM-1 and 2SM-5 should close when 2 ASP-B is energized. (A list of repositioned equipment is given in Enclosure 4.3 of OP/2/A/6100/04.) 09:44:26 Control transferred to AFWPTCP. (NOTE: S/G PORVs remain closed, breakers not yet energized.) 09:45:40 BOP operator at 2 ASP-A noticed the decreasing PZR level and was informed 2-3 gpm. by the control room that seal flow to the RCPs was around Operator went to increase on 2NV-294 controller which increased the demand signal and actually further closed 2NV-294 Charging flow decreased to 20 gpm. As a result of the decreased charging flow and the failing open of 2NV-148 letdown flow flashed completely to give an indicated letdown flow of 177 gpm. 09:45:45 BOP operator attempts to isolate letdewn by closing 2NV-13A (75 gpm letdown orifice block valve). 2NV-13A does not close (valve is stuck open). 09:46:55 BOP operator closes 2NV-1A and 2NV-2A to isolate letdown. 09:47:36 RO closes breaker for Train A power for AFWPTCP control of S/G PORVs A&B. 2SV-19 and 2SV-13 (PORVs A&B) open to approximately 75% valve position. 09:47:50

  -                      R0 closes breaker for Train B power for AFWPTCP control of S/G PORVs C&D.

valve position. 2SV-7 and 2SV-1 (PORVs C&D) open to approximately 75% 09:48:46 B0P operator operates 2NV-294 again, reducing charging further. RCS Pressure 2162 psig Tc Loop C 552'F Th Loop C 552 F PZR Level 0% Charging 6 gpm Letdown 17 gpm 09:49:48 Automatic safety injection signal received but blocked by design with control at the ASPS and AFWPTCP.

                         ..                            6 Partial phase A valve isolation of non-blocked valves.

RCS Pressure 1843 psig Tc Loop C 531"F Th Loop C 532*F PZR Level 0% Charging 6 gpm Letdown 6 gpm 09:50:24 RCS pressure reaches 1699 psig, narrow range pressure is off scale, pressure indication now unavailable at ASPS. 09:51:31 " Approaching loss of Adequate Subcooling" alarm received from SPDS in the control room. 09:51:35 Centrifical charging pump 28 is started from ASPS. 09:52:31 " Loss of Adequate Subcooling" alarm received from SPDS. 09:53:12 2SV-1 (S/G 20 PORV) closes. 09:53:14 2NV-1A (letdown to regenerative heat exchanger) opened. NOTE: Timing of above two events questionable due to computer backlog. 09:53:18 Control returned to the main control board. Automatic safety injection initiated. RCS pressure reaches lowest value. RCS Pressure 702 psig Tc Loop C 502 F Th Loop C 503 F PZR Level 0% Charging 125 gpm Letdown 0 gpm 09:53:26 2SV-7 (S/G 2C PORV) closes. 09:54:04 2SV-19 & 2SV-13 (S/G 2A & 2B PORVs) close. NOTE: PORVs close automatically on transfer to main control room. 09:54:25 " Approaching Loss of Adequate Subcooling" alarm cleared 09:55:30 Pressurizer level back on-scale. 09:58:10 Residual heat removal pumps 2A & 28 secured. 09:58:14 Safety injection pumps 2A & 28 secured. 09:58:20 Centrifugal charging pump 28 secured.

                .             -: .-                         7 10:00:00 RCS Pressure               1250 psig Tc Loop C        474 F Th Loop C        474 F PZR Level         34 %

Charging 36 gpm Letdown 0 gpm

b. Operators' Response to the Event The applicable procedure during this test was a marked-up version of AP/2/A/5500/17, Loss of Control Room. Interviews with the shutdown panel crew indicated that the appropriate Immediate Actions were performed and Enclosure 1 (ASP Operator Actions) and Enclosure 2 (AFWPTCP Operator Actions) were in the process of being followed when several pre-existing conditions and malfunctions complicated the event.

At step 3 of Enclosure 1, the ASPS were shifted to local control about 30 seconds after reactor trip. Charging flow drcpped from 80 gpm to about 39 gpm due to the pre-set valve positions of 2NV-309 and 2NV-294. Also, 2NV-148 failed open decreasing pressure downstream of the o ri fi ce.s . This caused letdown flow to flash, which the operator saw as flow oscillations between 60 to 105 gpm. In following Enclosure 2, the operators ensured that the S/G PORVs were closed (breakers in 0FF position) prior to transferring to local control at the AFWPTCP. There

           ~~

is an additional note and an instruction in this enclosure to aid the operator in verifying PORV closure; NOTE: MSIVs AND S/G PORVs automatically CLOSE when control is transferred to " LOCAL" at the ASPS. Also,

     ,                STEP 3        When directed by ASP operator, MANUALLY operate S/G PORVs to control NC temperature:

a. Ensure manual loaders set to maintain S/G PORVs:

FULLY CLOSED. The cperators believed that steam header pressure (indicated by the black needle) lower than setpoint (1125 psig on the red needle) ensured that the PORVs were closed. (See Figure 3.) _At 2 ASP-A, the operator was concerned with the oscillating letdown flow and the decreasing pressurizer level, and had received word from the control room that RCP seal flow was low. He tried to operate 2NV-309 and seeing no response, increased the setpoint of 2NV-294. Due to mislabeling of the valve charging flow actually decreased to about 20 gpm (at trip plus three minutes). He then saw the letdown flow spike to about 170 gpm and tried to isolate letdown by closing 2NV-13A. When this valve failed to indicate closed, he shut 2NV-1A and 2NV-2A. All of these actions were appropriate according to AP/2/A/5500/17 and AP/2/A/5500/12, Loss of Charging or Letdown. t _~ _ __ _

                                  ...                                8 The SRO was monitoring RCS temperature and S/G wide range levels.          The operators stated that possible over-cooling by auxiliary feedwater flow was stressed at their pre-test briefing. Since S/G levels were increasing, AFW flow was being throttled. Approximately five minutes after the reactor trip, the AFWPTCP operator closed the breakers for the S/G PORVs which resulted in the valves going to about 75% open.

(The two sets of PORVs opened about 14 seconds apart.) Pressurizer quickly. pressure and level immediately started dropping very About 70 seconds after the first two PORVs opened, pressu-rizer level went to 0%, and narrow range pressurizer pressure, the only indication in less than three available at the ASPS, went off scale low at 1700 psig minutes. transferred back to the control room.Af ter another three minutes, control was For approximately six minutes after the PORVs opened, the shutdown panel crew was faced with all of the classic symptoms of a LOCA or a severe over-cooling transient. During this six minutes, the AFWPTCP operator, believing the PORVs may be causing the problem, increased their setpoints to the top of the scale. This resulted in the valves going to the full open position. Also, the SRO, concerned over pressurizer level and VCT level, directed that the second charging pump and 'a boric acid pump be started and the suction valves from the refueling water storage tank be opened.

                        .Although all operators were aware that automatic initiation of safety
          -     --         injection was defeated at the ASPS, prompt action was not taken to manually initiate safety injection. EP/2/A/5000/01, Step 5.a. requires that safety injection be manually initiated if any of the initiating parameters exceed their setpoints (e.g., S/G pressure less than 725 psig or pressurizer pressure less than 1845 psig). The intent of this   action is for the operator to manually backup a failed automatic actuation.      This event was not specifically covered by the EP in that the automatic initiation was blocked, not failed, and the plant was being controlled remotely rather than from the control room. In addition, Catawba does not have the capability to manually initiate safety injection from the shutdown panels in a manner similar to that of the main control room, i.e., initiation switches. Instead, indi-                   '

vidual actions at other remote locations must be taken to start SI pumps and open injection valves in order to compensate for the decrease in RCS inventory or volume. As mentioned previously, the shutcown panel SRO began to direct that some of the necessary actions (start second charging pump, open RWST valves) prior to control being trans-ferred back to the main control room. However, these actions were not procedurally directed nor were they completed prior to transfer. Once control was transferred back to the control room, the operators were injection.aware of, and anticipated the automatic initiation of safety The inspectors determined that when control was transferred back, the operators followed the applicable emergency procedures. l

9 These procedures included EP/2/A/5000/01, Reactor Trip or Safety Injection and EP/2/A/5000/101, S/I Termination Following Steam Line Break. Safety injection was properly terminated with pressure greater than subcooling psig 1200 and increasing, of approximately pressurizer level greater than 33% and 100*F.

c. Plant Response and Analysis of the Transient (1) Cooldown Rate Technical Specification 3.4.9.1 b limits the cooldown rate to 100 F in one hour. Computer-logged data are available with one-second timepressure.

pressurizer resolution for loop hot and cold leg temperatures and Review of these data confirmed that the maximum cooldown was experienced by A loop, for which the decrease in cold leg temperature was 90*F and the decrease in average - temperature, upon which fracture toughness considerations are based, was 95.5*F. These changes occurred in about eighteen minutes. The net changes over the hour were less. (2) Shutdown Margin Technical Specification requires that the shutdown margin in modes 1, 2, 3, and 4 be greater than or equal to 1.3 % delta k/k. This specification is rooted in the need to maintain the reactor subcritical following the positive reactivity addition from the cooldown of the reactor coolant system following the steamline break accident at end of core life. with this event. To assure sufficientThat accident has analogies moveable reactivity control is always available, power-dependent control rod insertion limits are specified in Figure 3.1-1 of the Technical Specifications. At 25% of rated thermal power, the figure requires that 0 bank be at least 15 steps withdrawn. the trip was 171 steps. The actual position of D bank prior to the cooldown was 465*F in one cold leg.The minimum temperature At that temperature the atta calculated baron concentration required to maintain the shutdown margin is 735 ppmB. The measured concentrations six hours prior and 45 minutes after the event were 770 and 764 ppm 8 respectively. At 764 ppmB the excess shutdown margin is at least 0.377 delta k/k. (3) Saturation Conditions The safety parameter display system (SPOS) provides an alarm whenever the reactor coolant system (RCS) is less than 10*F subcooled. Using that value as a criterion, the hot leg and pressure data described in item (1) above were reviewed to evalu-ate the saturation conditions. It was determined that the RCS was less than seconds. 10 F subcooled for 58 seconds and was saturated for 13 Although these calculational results differ slightly from the SPDS output they confirm the validity and conservatism of the SPOS.

                                  '-~                         10 (4) Vessel Level Immediately following the transfer of control back to the control room, but after initiation of SI, the shift technical advisor (STA) and operator at the controls (OATC) made frequent checks of the reactor vessel level indication system (RVLIS) and confirmed a full vessel.

However, an inspector calculated the RCS water inventory immedi-ately prior to scram and compared it with the mass required to fill the RCS, exclusive of the pressurizer and surge line, at the condition during the period of saturation. There was a mass shortfall of about 3800 lbs., which indicated a net void of about 79 cubic feet. It is not clear whether the void was distributed throughout the system or localized in the vessel head. The licensee estimated that immediately prior to SI initiation, at which time the RCS was subcooled, the void may have been as large as 500 cubic feet. In that case, the hot legs would not have been full, but the core would have' remained covered. Discussions with operations personnel and those performing the post-trip review confirmed that no reactor coolant pump vibration alarms were received or unusual behavior observed during the transient. The

                  '-              cold legs, pump suction, were subcooled throughout the event. The pumps continue to operate without indications of problems.

Since the event, the licensee and Westinghouse have evaluated the accumulation of non-condensible gas in the control rod drive housings and the system high points, and have concluded there are no adverse consequences.

7. Human Factors Deficiencies

a. Deficiencies in Instrumentation Design To assess whether the event was caused by or exacerbated by human engineering deficiencies, the inspectors requested a detailed briefing and walkthrough of the event scenario. The operations engineer who had coordinated the Loss of Control Room Functional Test conducted the briefing and walkthrough. Incidental information was also provided during the walkthrough by operators in the Unit 2 control room and a design engineer from Duke's corporate Electrical Division.

At the request of the inspectors, the walkthrough was preceded by a short session in the Unit 2 control room during which the Loss of Control Room procedure was walked-through using control room instru- ! men:s. This was done to familiarize the inspectors with the control roon counterparts of the equipment that is used at the ASPS and at the AFhPTCP. This familiarization session provided a basis for identifying inconsistencies between control room instruments (routinely used) and j ASP instruments (rarely used). During the control room walkthrough, l L_

11

   -                 some instances of poor design practice were noted, e.g., reversals of the usualfull meaning      valve  position convention of 100% meaning full open and 0%

closed. The subsequent walkthrough of the event at the ASPS and AFWPTCP con-firmed that human engineering deficiencies, and inconsistencies between the Unit I and Unit 2 control rooms and their associated shutdown panels during the did,event. indeed, exist and did cause significant operator confusion A specific and dramatic example is the difference between the steam generator PORV controls and displays in the control room and those at the AFWPTCP. This example is reported in detail here because the poor design of the PORV controllers and their inconsistency with Unit 2 control room equipment event. were key factors in the initiation of the June 27, 1986, During the inspection it was determined that the actual antecedent of the event was a poorly implemented plant modification, DCA-CN-2-M-1527, that was completed in November, 1985. At that time a pneumatic control system was installed on the steam g'enerator PORVs to replace the non-safety grade, pressure actuated control system that was then in The instruments in the control room were changed from a pressureplace. setpoint controller and an associated steam generator pressure meter to a manual valve position controller and valve position indicator lights. However, the systems engineer in charge of the modification did not specify that the displays and controls on the Unit 2 AFWPTCP should be changed, redesigned, or replaced to reflect the new control mode. They remained unchanged. From the operator's point of view at the AFWPTCP, the modification was invisible. Figure 2 shows the manual PORV cartroller and associated valve position lights for steam generator 2D as modified in the Unit 2 control room. Figure 3 shows the unmodified controller that was in use at the Unit 2 AFWPTCP. As can be seen, there are significant differences between the instruments. Since no modification had been done to the AFWPTCP controllers, they still retain the misleading labels, " Steam Pressure Control" rather than "PORV Manual Control". The scale did not reflect valve position but rather stean generator pressure (note: the designations 0 and C for open and closed were added after the event). The engineering units were not specified and were not known by some of the operators some apparently thought this scale indicated millions of pounds of steam per hour rather than thousands (Roman Numeral M) of pounds of pressure (PSIG). Regardless, the use of this scale impTied that the controller was pressure setpoint actuated and not a manual. valve position controller.

                                                              , , _        _ _ _ _ - - . , . , - - - - - - - - ' " - - - ' * - ' - ~ ~

_ " - ~ ~ ~ '

                     . . .                           12 Prior to November 1985, when using the setpoint-actuated controller (see Figure 3), the operator selected a pressure setpoint by rotating the control knob (in a clockwise direction to increase tne pressure               ,

setpoint, counter clockwise to decrease). When actual S/G pressure (the black pointer on the right) incraased above the demanded setpoint (the red pointer on the left) the PORV would open. After the PORV modification, the indicator portion of the scale (black pointer) still showed S/G pressure, but the control portion (red pointer) was now wired to control valve position not S/G pressure setpoint. On or about June- 23,1936, an operator was dispatched to the AFWPTCP ' end the ASPS to verify that the panels were properly set up for the June 27, Loss of Control Room Test. used, Enclosure 4.5 of OP/2/A/6100/04,The procedural incorrectly checklist directed him tothat he adjust the setpoint on the steam generator PORV controllers to 1125 psig. Prior to the November 1985 modification, this action would have assured that the PORVs would remain closed after a transfe of control from the control roem to the ASPS. After the November 1985 modifi-cation, however, this action resulted in a pre set control signal demanding the PORV's to be modulated 75% open. On June 27 when the Loss of Control Room Test was being conducted, the operator at the AFVPTCP control room. first powered up the panels and transferred control from the they immediatelyLater he transferred stroked open. Thecontrol of the S/G PORVs, and ASP operator saw S/G pressures dropping and directed the AFWPTCP operator to verify S/G PORV's closed. Having no direct indication of PORV position on the AFWPTCP, the operator attempted to ensure that the PORVs were closed by further raising the setpoints on the controllers. The effect was to open the PORVs even further. the problem and regain control of the plant, but were unsucces After atout five and a half minutes, control of the plant was returned to the control room. Discussion with licensee personnel from the corporate Electrical Division revealed that, although a human factors evaluation of the PORV modification

              - Handling", no   was   required review  was by Procedure actually done.E0P 3.17, " Control Room Changes affecting the control room and all auxiliary shutdown panels.EDP 3.17 addre It should be noted that this S/G PORV modification will be done on Unit I 2.C.18).

graph during the first refueling outage (see License NPF-35, Para-Currently, the controllers in the Unit I control room and the Unit 1 AFWPTCP are pressure setpoint actuated controllers virtually AFWPTCP. identical to the ones that caused the problem in the Unit 2 Until Unit 1 is shut down, this poses a potential problem at a site tors. with a two unit shared control room and cross-licensed opera-Differences and inconsistencies between the Unit I and Unit 2 control rooms, between the control rooms and their associated auxiliary 6 o

13 shutdown pansis become sources o,f confusion.and between auxiliary shutdown panels themselves m As described later in this report, the operators invol "md in the test specifically discussed whether the 1 were none. changes to the PORV controller and concluded that there were Since PORV controllers in the Unit 1 control room, the Unit 1 AFWPTCP, and the Unit 2 AFWPTCP were virtually identical', and since the procedures implied that there was no change, their conclusion was predictable. During the event it was reported that there were problems and possible operator confusion in regulating charging and letdown flow and in maintaining appropriate Reactor Coolant Pump Seal Flow. A review of the operations of 2NV-294 (charging flow control valve) and 2NV-309 (seal injection flow control valve) indicated that the controllers located on 2 ASP-A were labeled incorrectly. The controller for 2NV-294 had an increase / decrease label mispositioned so that when an operator went as thetooperator increase on the controller, the valve shut instead of opening intended. In addition, the 2NV-309 controller had the open/ closed label mispositioned. This labeling error led the operator to believe that increasing the controller signal in the open direction would increase seal flow. It caused the seal flow to decrease. Although the apparent problem is mislabeling, the more basic problem, the problem that caused the errors in labeling, is lack of consistency.

    *     ~

Throughout both control rooms and all six auxiliary shutdown panels, valve controllers are inconsistently formatted, i.e., sometimes 100% means 100% open, in other cases the instrument logic is reversed and 100% means 100% closed. Because of this inconsistency within and among control areas, operators open and closed positions. found it necessary to add labels to designate Because the process used to implement this labeling program was not well-controlled, some controllers were mis-labeled. A similar case exists with the labeling of I, for increase and D, for decrease. There is no plant convention implemented for where these labels should be placed on the controllers and development of such a convention may be impossible. In some cases, piping configurations are such that an increase in flow, e.g., to reactor coolant pump seals, is accomplished by closing certain valves. In those cases the I would have to be placed on the zero end of the valve position scale. This is contrary to conventional expectations and, in fact, is a misuse of labeling (see Finure 4). Generally, a label should clearly state the immediate function of the equipment, not the ultimate function. That is, a valve controller should be labeled open/ closed not increase / decrease. The ultimate function should be covered in training and procedures, e.g., " Increase flow by opening NV 148 and closing NV 309". The face of a meter is not an appropriate place for procedural guidance. f

14 This problem team. the inspection is related to other labeling discrepancies identified by In some cases, valve controllers are labeled with misleading nomenclature (usually related to ultimate function), e.g., Figure 5 shows a valve controller / valve position indicator that is labeled "CA PUMP 2A FLOW...". In this example, the operator is faced with a serious dilemma - apparently, one must increase the demand setting to 100% to close this valve, but what should the operator , expect to see happening on the actual indication side of the scale? Since the label says FLOW, does zero mean no flow? As explained to the inspectors, this is not a flow meter but a valve position indicator. Therefore, the actual indicator would, in this case parallel the (assumably) 100*.demandflow.indicator with zero indicating full open or, In addition to the above problems of incorrectly located labels and misleading labels, the inspection team identified several instances where labels were either meaningless or were totally absent. Figure 6 shows three letdown valve controllers that were involved in the charging and problems. As can be seen in the figure, none have descriptive labels Loader. - just a valve number and the relatively meaningless term Manual No engineering units have been specified, and, as mentioned earlier, the 0/C and I/O labels are on the wrong ends of the scales on 2NV 309 (seal injection flow control valve) and 2NV 294 (charging flow control valve).

        ~

Following the briefings and walk-throughs on June 28 and 29, two members of the team went to Duke Corporate Offices to interview design engineers who were familiar with the Catawba control room design review (CROR), shutdown apanels.human factors evaluation of the Catawba control rooms and The purpose of these discussions was: (1) to deter-mine whether Duke Power had previously identified (e.g., during the

    .          CROR) the human engineering discrepancies that had been observed during the walk-throughs of the control rooms and auxiliary shutdown panels; and if .ct, why not; and (2) to identify whether a specific human factors review of the PORV modification was done.

The inspectors, after sreveral hours of discussion, determined that Duke Power had identified all of the deficiencies observed by the team (except those that came to light only as a result of the Loss of Control Room Test, such as the PORV change and the open/ closed label reversals). The team was shown documents that provided evidence that the licensee had identified the observed deficiencies during the CROR in late 1982. Corrective actions have been developed and approved by Duke management, and the currently operative plan is to implement the corrective actions during each unit's first refueling outage. effort, as described, appeared to be comprehensive. CorrectiveThe CROR actions were well planned and when implemented, should be effective in reducing the incidence auxiliary of hardware-induced shutdown panels. errors in the control rooms and

                     -.                             15 Regarding the PORV modification and label reversals, the team reached two conclusions. First, the PORV modification was within the scope of the licensee's procedure, EDP-3.17, Control Room Changes-Handling.

This procedure requires that any changes affecting the Control Room and/or the auxiliary shutdown panels shall be reviewed by members of the Control Complex Engineering Group. One member of this group is specifically neering responsible for reviewing changes for their human engi-acceptability. The changes to control room equipment caused by the PORV modification were reviewed. The auxiliary shutdown panels, however, were not reviewed. This was described as "an oversight". Second, the labeling of instruments with regards to open/ closed and increase / decrease was performed by operations personnel on shift. This work was required to be done in a manner consistent with Duke Power humanOMP Procedures, factors l-6).guidelines and conventions (Operations Management Because the labeling process lacked rigorous controls, some labels were positioned at the wrong ends of some instruments. In light of the above procedural deficiencies, doubt was cast on the quality of review that was done on all past plant modifications affecting the control rooms and auxiliary shutdown panels. In addi-tion, the quality of the labeling program in the main control rooms was also questionable. On July 1, 1986, members of the inspection team toured a separate, independent shutdown facility called the Safe Shutdown Facility (SSF). This facility provides a shared environmentally protected backup to the six auxiliary shutdown panels. The inspectors identified no obvious deficiencies during the tour. Because of the questions raised concerning the event, especially the

  -           possible implication that the main control room could contain signifi-cant deficiencies, the inspectors briefed the plant manager and the operations supervisor on what actions should be taken to correct human engineering deficiencies prior to restarting Unit 2. The briefing items were noted by the operations supervisor and plant manager without comment or specific commitments.

These items are listed below: (1) Verify by a well-controlled method, e.g. , comparison with controlled design drawings or actual manipulation, that the 0 and C labels that are affixed to some instruments to designate open and closed positions are correctly located on the instru-ments, i.e., the 0 is really indicating the open position and C the closed. This verification should be done on all six ASPS and both control rooms.

                  ,        -: -                         16 (2) Verify by a well-controlled method that the I and D labels, currently affixed to flow controllers to designate increase and decrease, are correctly located on the controllers, i.e., the I is really indicating the valve position that increases flow. Where the flow controller has an associated valve position indicator, the 0 and C indicators should be verified as being correct and consistent with the flow controller. In those cases where a flow controller does not actually measure flow but rather measures valve position, the identifying label should be revised to reflect its true function and the I and 0 labels replaced with 0 and C.

These actions should be done for all six ASPS and both control rooms. (3) The steam generator pressure reitef valve controllers in the AFWPTCP should be relabeled to reflect that they are valve position controllers rather than pressure setpoint controllers. In addition, the scales should be revised appropriate to the new control mode and enhancements added to emphasize their difference from the Unit 1 S/G PORV controllers. (4) Add labeling to all six ASPS as necessary to clearly identify all components, e.g., general nomenclature such as Manual Loader should be changed to a specific title such S/G Pressure Relief Valve Position Controller. Consistency of nomenclature should be maintaine.d throughout the ASPS and control rooms, e.g., if necessary, labels may need to be added or revised in the main control rooms. (5) Add labeling to all 6 ASPS as necessary to clearly identify the variables measured and the engineering units they are measured in. This should be done for all meters and indicators at the six Asps. (6) Develop an accelerated schedule for the modification package, (NSM) shutdown CN-20227, panels. that implements corrections to the auxiliary One item of high priority, in addition to those mentioned in items 1 through 5, above, is the replacement of the narrow range reactor coolant system pressure instrument (1700-2500 psig) with a wide range instrument. (7) Develop an accelerated schedule for correction of human engineering deficiencies in the control rooms, as well as the ASPS, that will minimize the differences between the Units. (The current schedule would implement improvements to Unit I by the end of its first refueling (Summer 1986) while leaving Unit 2 unimproved until late 1987 or 1988 (Unit 2 refueling)). This schedule will not only leave Unit 2 unimproved for another 20 months betweenbut thewill twocreate units. more differences and inconsistencies Offferences should be minimized at a plant, such as Catawba, that cross-licenses its operators for both units). 6

    ,Y Q g   .

o

b. Training This assessment of training was conducted through interviews with licensed operators and supervisory personnel as well as a review of written procedures and training material. Tne event has revealed training deficiencies concerning the instrumentation and controls contained on the shutdown panels, as well as inadequate pre-test training of the participants.

Auxiliary Shutdown Panels With regard to the ASPS, the inspectors reviewed training handout OP-CN-H0-RSS and the accompanying lesson plan for the remote shutdown capability. The lesson plan was generally comprehensive concerning the purpose and function of the ASPS, howeve , it did not include a description of the individual controllers nor did it include informa-tion on how the operation of the controllers differed from their counterparts in the control room. Interviews with training personnel revealed that training on process instruments and controllers is, for the most part, performed at the Duke Training Center at the McGuire Station. This training is partly classroom but primarily " hands-on" using the McGuire simulator. Process instruments are very similar between the McGuire and Catawba sites. In addition, general and site-

           -          specific process instruments and controls are taught at Catawba (e.g.,

OP-CN-SS-IG, Instrumentation General Lesson Plan). However, the inspectors found no evidence that formal training is conducted on the remote shutdown panels' instruments and controls. Several Catawba personnel were questioned on the operation of seal water injection flow control valve, 2NV-309. This valve is capable of being controlled from either 2 ASP-A or 2 ASP-B. The controlling signal.

• is the auctioneered higi) from either controller. Not all personnel Questioned were aware of this fact, nor were any aware that the valve is reverse-acting and the controller on Unit 2 was labeled backwards.

Indeed, the BCP operator on 2 ASP-A, during the event, thought that 2NV-309 was initially closed. When he san no response on charging flow after attempting to "open" the valve, he reset it to its original position and disregarded it, believing it to be malfunctioning. The valve had been preset according to Enclosure 4.5 of OP/2/A/6100/04 to what was thought to be fully closed when, in fact, it was fully open. The SRO who had completed Enclosure 4.5 prior to the test was questioned on the operation of charging flow control valve, 2NV-294 He set it to control at 32 on a scale of 0 to 100 believing (erron-eously) the scale to read in gpm and not knowing that this controller was also labeled backwards. This controller is labeled "I" for increase at the top of the scale and "D" for decrease at the bottom. Both the SRO and the BOP operator at 2 ASP-A during the event believed they were opening the valve by raising the setpoint toward "I" when the

                          . . .                         18 valve was actually closing. Operations Management Procedure 1-4, "Use of Procedures" contains a constrained language list of terms which are currently used in operating procedures. Although the terms open and closed are defined on the list, the terms increase and decrease are not.       Interviews with operators revealed confusion as to whether increase and decrease related to changing the signal to the valve, the parameter controlled by the valve or the valve position.

Currently, Catawba personnel are trained on the McGuire simulator. Duke has contracted for and expects delivery of a Catawba specific simulator in late 1987. Remote shutdown panel simulation will be a unique feature for the Catawba simulator. PORV Modifications The PORVs on Unit 2 were modified accordfrg to Design Change Authoriza-tion (DCA) No. CN-2-M-1527, dated January 18, 1985. The inspectors reviewed the lesson plan generated to describe this modification, attendance records for that segment of requalification training, and interviewed the STA who was respons.ible for the lesson plan. The STA stated that normally DCAs are not reviewed for incorporating plant changes into requalification training but Catawba Administrative Procedures do address the process for reviewing Nuclear Station Modifications (NSMs). A review of Operations Management Procedure

       '   ~       1-12, Operations NSM Implementation Process, supported this statement.

The STA apparently generated the lesson plan on his own initiative in late 1985 or early 1986. The inspectors also interviewed the requal-ification instructor (by telephone). Neither of the individuals were aware of any changes in the operation of the shutdown panel Unit 2 PORV controllers, although both stated they tried unsuccessfully to get this information from the Duke Power Company Design Engineering Department. Other additional licensed and supervisory personnel in the Catawba Operations Department were interviewed and all stated they were unaware of any change in the operation of the PORV controllers. This change in the controllers is not apparent in the DCA description. In addition to lack of knowledge on the controller modifications, most personnel interviewed were unfamiliar with the scale units which are labeled M (e.g. , .9M,1.2M,1.5M). Some individuals thought it meant million as in million pounds per hour of steam. Others, including the SRO who set the controllers to 1125 psig several days before the test, admitted they did not know what the "M" designated. Apparently the M is Roman numeral for 1000 and the psig must be inferred by the operator. In general, the inspectors found the training personnel to be very conscientious with regard to plant modifications training and appropri-att procedures are in place to ensure post-construction changes (NSMs) are adequately covered. However, since the PORV modification was made by a DCA instead of an NSM, its inclusion in requalification

'f 19

          ,            r training was only due to the initiative of the people involved. Also, the failure to recognize the controller modification can be attributed to poorEngineering Design    communication     between the Catawba site personnel and Duke Department.

Pre-Test Training All of thetraining pre-test personnel involved performed or were interviewed concerning the scopt of Room Test. received prior to the loss of Control The three licensed personnel on the shutdown panels were specifically chosen because of their prior experience on similar tests and the fact that they were in a requalification training status. The SRO was in the control room during the Unit I test. The R0 on the AFWPTCP had performed the identical function during the Unit 2 hot functional same test,during position and thetheBOP Unit 1operator test. on 2 ASP-A was an observer in the The test coordinator, an STA and licensed SRO, briefed the shutdown panel crew the day prior to the test. This training session was approximately one hour long, conducted in a classroom and consisted primarily the test. of reviewing the three p'rocedures that were to be used during This crew later, without supervision or instructors, visited their local stations and walked through the applicable procedures. They stated to the inspectors that they specifically talked among themselves about changes to the PORV controller and concluded there were them. no changes since no one recalled any information being provided to It should be noted that the presence of an instructor would not have corrected this lack of information since no one in the Operations of Training Departments were aware of the controller modifications. The short.briefing for the control room crew was informal and relatively The control room crew were given the procedures to review and told the importance of not invalidating the test by providing too much information to the shutdown panal crew. Following the Unit 1 test, the observing NRC inspectors coaching from the control room. noted that there appeared to be excessive The Unit 2 crew were sensitized to providing a minimum of information and thus ensuring test validity. The shutdown panel crew expected to be relayed only information concerning adequate reactor coolant pump seal injection flow. The test coordinator stated to the inspectors that even though the control room crew knew that the PORVs were open, they decided not to inform the shutdown panel crew for fear of invalidating the test. There were to procedures) apparently no test termination criteria (via training or either crew. Although it is impossible to anticipate or postulate all conceivable malfunctions, it should have been under-stood that the plant parameters should be able to be controlled within the rarge of available instrumentation. Since pressurizer level went to 0*4 and the narrow range pressurizer pressure instrument went off

\

7

            .                                                                                   s
                       ...                          20 scale low at 1700 psi, there was a period of time (approximately two minutas) that neither parameter was available to the shutdown panel crew before control was transferred back to the control room. Also, most of the control room crew were unaware of the limitation in span of the ASP pressurizer pressure indication.

8. Equipment Malfunctions and Procedural Deficiencies

a. Equipment failures during the event:

(1) 2NV-148 (low pressure letdown control valve). This valve is set to maintain pressure downstream of the letdown orifices. Before the event the valve was set at 350 psig and controlled from the main control room panel. When control was shifted to 2 ASP-A, the control of 2NV-148 shifted to the controller located on that panel. Upon transfer, the valve failed to the full open position (the normal valve failure mode). Trouble shooting determined that the 2NV-148 automatic controller on 2 ASP-A had no D.C. power input from its pressure transmitter, but the controllers manual function was not affected. The cause was traced to a poor connection at sliding link (K-29). Following this event, a proper connection was made; the valve was functionally tested from the shutdown panel and found satisfactory.

   '      ~

(2) 2NV-13A (letdown orifice outlet containment isolation valve). This valve failed to close using t;.a manual switch located in the control room and at the ASP. Investigation determined that the valve was stuck on its backseat. After the event, by using the local hand wheel the valve was unstuck and remotely cycled four (4) times, with satisfactory response time. The probable cause was flashing of letdown flow caused by the failure of the 2NV-148 valve and minimum cooling of the letdown flow through the letdown regenerative heat e'achanger. The letdown flashing caused thermal expansion of 2NV-13A, causing the valve to bind. (3) Diesel generator 2A load sequencer exceeded the loading time requirements for load group seven (nuclear service water pump). The sequencer loaded group seven 2.326 seconds after loading group six. The required time limit is 2.0 .2 seconds. Investi-gation determined that the sequencer was out of calibration. The licensee recalibrated the sequencer and functionally retested diesel generator Train "A" load sequencer. The sequencer tested satisfactory,

b. Equipment that was thought to malfunction but subsequently found to operate as designed:

• 21 (1) 2CA-58A (motor driven auxiliary feedwater pump 2A discharge to steam generator 28 isolation valve) shut during the event and

                     '                  isolated the motor-driven feedwater supply to steam generator 28.

drivenThe S/G continued auxiliary feedwatertopump. receive feedwater from the turbine-2CA-58A is designea to shut

                 ,                     automatically on a high motor-driven pump 2A discharge flow setpoint of 780 gpm increasing flow. This action is provided as a pump runout protection feature. A review of S/G flow rates before the valve isolated and after isolation indicated the motor-driven pump was providing approximately 880 gpm flow rate. It appears the event.the valve shut as designed to prevent pump runout during (2) 2NV-294      (charging flow control valve) performed contrary to the operator's expectations. The licensee investigated the possi-bility that the valve was improperly wired. A review of the electrical drawings and functional verification of valve opera-tions determined the controller was direct acting and that the controller was incorrectly labeled.

(3) 2NV-309 (seal injection flow' control valve) performed contrary

               '                      to the operator's expectations. The licensee investigated the possibility that the valve failed to operate properly. A review of the electrical drawings and a functional verification of valve
                      --              operations determined the controller was reverse acting and that the controller was incorrectly labeled.

(4) Main steam isolation valve bypass valves would not open after reset. On investigation of the reset switch, the relays worked properly and no problems were found. The reset was functionally tested and the main steam isolation bypass valves operated satisfactory. On investigation of the initial malfunction, the

         -                           licensee indicated,that the operators may have failed to reset all required reset switches. To reset the bypass valves, three reset switches needed to be reset, Train "A" and "B" main steam isolation valve       signal reset and the main steam isolation valve bypass reset.

c. Procedural deficiencies affecting the event:

(1) OP/2/A/6100/04, Shutdown Outside the Control Room From Hot Standby, was deficient in several areas. Enclosure 4.5 was not revised to correctly reflect the operation of the PORV controller. The operator completing the Enclosure was directed to set the setpoints for the four PORVs to 1125 psig. This procedural inaccuracy, in addition to the human factors deficiencies noted earlier in this report, resulted in the controller demanding a valve position of 75% open once the control power breakers were shut. 9

22

     -                           Enclosure 4.5 was also deficient in the requireo' settings for 2NV-309 and 2NV-294. The procedure had a temporary change dated April 21, 1986 which established the 2 ASP-A control position for 2NV-309 to be "In auto and turn poter.tfometer setpoint counter clockwise until potentiometer bottcas out for closed positior."

This actually resulted in the valve being in the fu'lly open position. Also, the 2NV-294 valve was supposed to be set for 32 gpm. This did not acknowledge that the valve controller is reverse-acting and that there are no units on the 2 ASP-A controller scale. Valve NV-294 was therefore set for 32% closed which happened to correspond to about 40 gpm flow rate. (2) TP/2/A/2650/03, Loss of Control Room Functional Test, dated February 20, 1986, was the procedure used to conduct the less of control room test on June 27, 1986. Section 6, Limitations and Precautions, Step 6.10, states, "if any situation arises that cannot be adequately controlled from the auxiliary shutdown panels, transfer control back to the main control." This precau-tion is inadequate due to the lack of specific test termination criteria. The termination cr.iteria should take into account the limitation of the auxiliary shutdown panels, i.e., temperature, pressure, pressurizer level indications and automatic safety injection requirements to list a few. (3) Operations Management Procedure (OMP) 1-6, Control Par,el Informa-tion Changes, dated May 10, 1982, is the procedure which defines the method by which information may be added, changed, and or deleted on control panels under Operations Group respo~nsibility, either as a permanent or temporary change. The inspector was concerned about the mislabeling of 2NV-294 (charging pumps A&B discharge plow control valves) and 2NV-309 (seal water injection

   -                          back pressure control valves) on the auxiliary shutdown panels.

The licensee infermed the inspector that these valves were labeled without the use of a procedure or work request. OMP 1-6 states,-

                              "any informational change shall conform to human factor guidelines used in the design of the station and agree with setpoints, limits, and precautions established in approved operating procedures."

The licensee failed to implement OMP 1-6 or an appropriate work request to ensure that 2NV-294 and 2NV-309 were properly labeled.

9. System Logic Design - Blockage of Safety Injection The design basis for remote shutdown is found in General Design Criteria (GDC) 19. " Equipment at appropriate locations outside the control room shallreactor, the be provided (1) with a design capability for prompt hot shutdown of including necessary instrumentation and controls to maintain t

a

 .                                                  23 T

the unit in a safe condition during hot shutdown, and (2) with potential capability for subsequent cold shutdown of the reactor through the use of suitable the procedures." following equipment:The auxiliary shutdown complex for Unit 2 consists of a. Auxiliary shutdown panels (ASP) 2A and 28 and associated cooling units. b. Diesel generator panels 2A and 2B and associated vent system. c. HVAC control panels 2A and 28 located in the HVAC equipment rooms, d. Auxiliary feedwater pump turbine control panel (AFWPTCP). e. Miscellaneous valves and equipment located throughout the plant. Each ASP position panel associated transfer switch. with the auxiliary shutdown complex has a two switch. The AFWPTCP has a train A and a train B transfer The normal position is Control Room or Remote. After control room evacuation, each switch should be placed in the Local position. Once transferred to local all control room signals are bypassed (defeated) and all equipment complex panels.will be positioned or con ~ trolled from the auxiliary shutdown listed in Appendix A is positioned.Upon engaging the transfer switches to local, the From a review of the positioned systems and components, and through

       ~ discussions with the licensee, it was determined that automatic actuation of the following ofety systems / components are blocked or isolated when control is shifted to the remote shutdown panel:

a. Intermediate safety injection (SI), power to the pumps is blocked but can above bethe restored ASP; in the MCCs located on the first and second levels

   ^

b. High head SI, the ECCS discharge valves (2NI 9A and 10B) are blocked closed, a charging path is established through the normal charging line, the discharge valves (2NI-9A and 108) can be locally opened by using the manual hand wheel on the valve actuators; c. Upper head injection is isolated and cannot be remotely operated. d. 2NF-228A, 233B and 234A ice condenser glycol supply and return isola-tion valves are blocked open; e. 2NM-3A, 78, 22A, and 268 NC loop A sample and pressurizer liquid sample isolation valves are blocked open. i

o 24 f. Varied upon SI systems actuation: are blocked from being loaded by the sequencers (A & B) (1) Containment spray pumps 2A & 29, these pumps can be manually started in the MCC's located 1 and 2 levels above the ASP. (2) Annulus ventilation system A & B, this is a post-design-basis-accident system that can be remote manually operated. (3) Auxiliary building ventilation system A & B, this system can be manually operated frem HVAC panels located on the 594 level. The NRC position regarding the blocking (disabling) of safety systems is provided in Section 7.4.2.2. Item 5 of the Catawba SER.

                                                                              " Manual transfer of control to the remote location (s) should not disable any automatic actuation of ESF functions or change the operating status of equipment while attaining or maintaining shutdown, other than where ESF features can be manually placed in service to achieve and maintain shutdown. It is permissible to disable automatic low pressure injection actuation in this manner when necessary to enable control of the RHR system from the remote location and while operating this system to effect cold shutdown from hot shutdown."

The blocking of the SI components associated with intermediate head SI and high head _ operation SI, is acceptable in that they are provided with remote manual capability. based on NRC evaluation of its contribution to safety In at McGuire.The i addition, it is permissible to block the containment valves of the ice condenser glycol system and reactor coolant loop A sample and pressurizer liquid sampl? system because they are left in the desired position for shutdown and are not required to change state. The blocking of the ESF systems: containment spray pumps A and B, annulus ventilation systems A

      -       and B, and auxiliary building ventilation systems A and B are acceptable in' that they are provided with remote manual operation capability.

In summary, listed above isthe NRC finds that the blocking of the system and/or components acceptable. However, it was apparent from a review of the remote shutdown Operating Procedures that there was no provisions for remote manual actuation of these systems and components. The licensee is required to prepare procedures for remote-manual operation of each of the items, other than the upper head injection system, ice condenser glycol system isolation valves and the reactor coolant loop "A" and pressurizer liquid sample isolation valves. The licensee must demonstrate during the loss of control room test that the remote manual operability actions for initiating SI, containment spray and auxiliary building ventilation are feasible. The annulus ventilation system remote manual actuation feasibility is to be demonstrated prior to acceptance of the loss of control room test. The above requirement is an inspector followup item (414/86-27-03): Demonstrate feasibility of manually initiating safety injection from outside the control room).

                                                                           ~-

    .y                                          ~
                           --                          25

10. Modification Control Upgrade of the S/G PORVs was done in accordance with Design Change Authori-zation DCA CN-2-M1527.

were discussed in the DCA.The main control board changes and the AFWPTCP associated with implementing the design change as follows:There appear Most of the design change involved S/G PORV control. Control was to be changed controller. position" from a " pressure setpoint varying" type of controller to a " valve The " pressure setpoint varying controller uses the technique of open the valve. adjusting PORV setpoint lower than steam generator pressure to valve position. The " valve position" controller directly operates PORV adequate for the main control board. Implementation of the design change appea However, the change for the AFWPTCP led to confusion because the operator was unaware that the same pressure setpoint valve varying controller was being used to indicate and control S/G PORV position. implemented from a human factors point of view because it re AFWPTCP had changed. operators being unaware that the way the PORVs were c During discussions with members of the team, design personnel stated that this design change was not reviewed for human factors considerations This . was not in accordance with Design Engineering Procedure EDP 3.17, Control

          ~

Room Changes - Handling, which requires that changes affecting the control rcom receive a human factors evaluation. This procedure applies to contral affecting the auxiliary shutdown panels. board and equipment layout c procedures when initiating this design change.The licensee failed to follow Work associated with implementing a DCA on a system after the system had been provisionally transferred from the Construction Department to the Nuclear a shutdown Production request. Departmentswas completed by construction personnel under design change which upgraded the S/G PORVs to Station safety related.There Directive 3.0.3, Management of Shutdown Requests, describes the administra-i tive controls Production for implementation of a shutdown request by the Nuclear Department. This station directive requires that the various (such as procedure changes, additional testing, Shut- etc.) are requ down requests completed for design change DCA CN-2-M1527 were inadequately

reviewed in that the reviewers did not recognize nor adequately emphasize valve position instead of setpoint.that a pressure setpoint controller was being revised and adequate training not being performed.This resulted in some proc Specifically, Enclosure 4.5 to Operating Procedure OP/2/A/6100/04, Shutdown Outside the l

e

26 Control Room From Hot Standby to Cold Shutdown, was not revised to initially set S/G PORV valve position to 0% open. The setpoints for the PORVs were still set at 1125 psig by the procedure which actually corresponded to a valve position of approximately 75% open. After team members discussed the problems associated with implementing this DCA, the licensee agreed to review all safety related design changes which were implemented by the Construction Department after Unit 2 hot functional testing and prior to receipt of the Unit 2 low power license. The changes were reviewed to determine if any affected operating or test procedures, or if any had human factors significance. The licensee completed the review prior to restarting Unit 2 and documented it in a memorandum dated July 3, 1986. In addition to the above review, the licensee conducted a followup review of all shutdown requests which implemented changar to systems or equipment. Followup review of the shutdown requests is documented in a memorandum dated July 11, 1986. Two additional items were identified which will require followup actions. Team members the auxiliary reviewed shutdown several nuclear station modifications (NSM) related to panels. It appears that administrative controls discussed in Station Directive 4.4.4, Processing Nuclear Station Modifica-tions, are adequate for ensuring that NSMs are revi?wed for followup actions such as procedures revisions, additional testing, and training. 11. Findings and Conclusions

a. Design Change Control Finding: The licensee was deficient in implementation of administra-tive controls in not ensuring that the S/G PORV design change received a HED review and was fully understood at the plant; and was not adequately reviewed for incorporation into procedures for the loss of

      -                  control room test and thaining of licensed personnel. This item will be identified as Violation 50-414/86-27-01, failure to establish, implement, or maintain procedures in accordance with Design Engineering administrative controls and Technical Specification 6.8.1.

Conclusion:

Administrative controls exist for ensuring NSMs are adequately translated into training and procedures, but not DCAs. Licensee reviewed all safety-related design changes implemented since completion of hot functional testing and identified two additional items which will require followup action.

b. Procedures Deficiencies .

(1) Findinci Procedures were inadequate with regard to a lack of appropriate test termination criteria and improper settings l ' at the ASPS and AFWPTCP. This led to a failure to initiate safety injection promptly by delaying the transfer of plant control back to the control room. This is another example of Violation 50-414/86-27-01. l l l 9 v.

   .y.ap,x .
                            --                             27

Conclusion:

Primary cause of the event was due to lack of knowledge of the design change that resulted in a procedure error which improperly set the S/G PORVs. Additionally, reluctance of the operators at the main control board to provide too much information to the crew at the ASPS for fear of invalidating the loss of control room test, combined with inadequate test termination criteria, caused the delay of nearly six minutes in terminating the test, even though the plant had reached safety injection initiation setpoint requirements. Once controls were transferred back to the control room, the operators were aware of, and anticipated the automatic initiation of safety injection and the applicable emergency procedures were followed. (2) Finding: Deficient implementation of administrative procedures regarding labeling of components on the ASPS. This is another example of Violation 50-414/86-27-01.

Conclusion:

Controllers for valves 2NV-294 and 2NV-309 were labeled improperly. or work request. This was done without the use of a procedure

c. Training Finding: Training was deficient in not adequately teaching the S/G

       ~     ~

PORV design change and the instrumentation and controls contained on the ASPS and the AFWPTCP. Appendix A to 10 CFR 55 requires that the licensee's requalification program include training so that each licensed operator and senior operator be cognizant of facility design changes. This item will be identified as Violation 50-414/86-27-02, failure to provide adequate operator requalification training in accordance with Technical Specification 6.4.1.

Conclusion:

The response of the licensed personnel during the event was appropriate considering the identified deficiencies in training and procedures. Previous NRC inspections and operator license examina-tion results are indicative of an overall satisfactory training program administered at the Catawba station. The program was deficient how-ever, in not providing instruction of the shutdown panel instruments and controls and the PORV controller modifications.

d. Human Factors Deficiencies Finding: Although a human factors review of the S/G PORV design change was required, none was done. Human engineering deficiencies resulting from the S/G PORV design were the major cause of the event.

The auxiliary shutdown panels contain many other human engineering deficiencies, some of which induced operator errors during the loss of control room test. (This item will be identified as Inspector Followup Item 50-414/86-27-03, Demonstrate feasibility of manually initiating safety injection from outside the control room.)

i 28

Conclusion:

Most of the human engineering deficiencies had been identified by Duke Power in November 1982, and some were discovered as a result of the event. All of the identified deficiencies are scheduled for correction, with specific deficiencies scheduled tc be corrected prior to restarting Unit 2.

e. Analysis of Plant Response Finding:

The plant did not violate any Technical Specification limits with regard to cooldown rate and shutdown margin. The RCS was less than 10 F subcooled for 58 seconds and was saturated for 13 second At the time the RCA was subcooled, the licensee estimated that the net void in the RCS may have been as large as 500 cubic feet.

Conclusion:

on the plant. There were no adverse thermo-hydraulic or nuclear effects

f. Safety Injection Logic .

Finding: Manual transfer of control to the ASPS disabled automatic actuation of ESF functions and changed the operating status of equipment.

Conclusion:

Blocking of ESF functions is acceptable provided the

       ~

components shutdown. can be manually placed in service to achieve and maintain The licensee is required to prepare procedures for remote manual operation of the components blocked and must demonstrate the feasibility of manually initiating safety injection from outside the control room during the loss of control room test.

APPENDIX A EQUIPMENT POSITIONED BY TRANSFER TO LOCAL CONTROL AT ASPS AND AFWPTCP A. All S s1 gic to Sequencer is negated. B. Nuclear Service Water (RN) Aligned Position 2RN-67A (RN Hdr 2A Supply Isol) Open 2RN-69B (RN Hdr 2B Sucoly Isol) Open 2RN-846A (D/G 2A Hx Rtn To SNSWP) Open 2RN-847A (D/G 2A Hx Rtn To Lake) Closed 2RN-848B (D/G 2B Hx Rtn To SNSWP) Open 2RN-849B (D/G 2B Hx Rtn To Lake) Closed 2RN-291 2RN-351 (KC Hx 2A Outlet Throttle Valve) Open (KC Hx 28 Outlet Throttle Valve) Open C. Component Cooling System (KC) Aligned Position 2KC-425A (NC Pumps Ret Hdr Cont Isol) Open 2KC-4248 (NC Pumps Ret Hdr Cont Isol) Open 2KC-3388 (NC Pumps Sup Hdr Cont Isol) Open

               ,_2KC-305B (Exs Letdn Hx Supply Cont Isol)               Open 2KC-3158 2KC-57A (Exs Letdn Hx Ret Cont Isol)            Open (ND Hx 2A Flow Ctrl)                    Open 2KC-828       (ND Hx 28 Flow Ctrl)                    Open D. Chemical and Volume Control System (NV)         Aligned Position 2NV-15B       (Letdn Cont Isol)                        Open
     .           2NV-328       (NV Supply To Loop A Isol)              Open 2NV-39A       (NV Supply To Loop D Isol)              Open 2NV-44A       (NC Pump A Seal Supply Cont Isol)       Open 2NV-52A       (NC Pump 2A Seal Return)                Open 2NV-55A       (NC Pump B Seal' Supply Cont Isol)      Open 2NV-63B       (NC Pump 28 Seal Return)                Open 2NV-66A       (NC Pump C Seal Supply Cont Isol)       Open 2NV-74A      (NC Pump 2C Seal Return)                 Open 2NV-77A      (NC Pump D Seal Supply Cont Isol)        Open 2NV-85B       (NC Pump 20 Seal Return)                 Open 2NV-89A       (NC Pmps Seal Ret Cont Isol)             Open 2NV-91B       (NC Pmps Seal Ret Cont Isol)             Open 2NV-153A (Letdn Hx Otit 3-Way Viv)                     To VCT 2NV-181A (B/A Blender Otit To VCT)                     Closed 2NV-18aA (VCT Otit Isol)                               Open 2NV-1898 (VCT Otit Isol)                               Open 2NV-202B (NV Pmps A & B Recirc Isol)                   Open

.' ' Appendix A 2 2NV-203A (NV Paps A & B Recirc Isol) Open 2NV-242A (RMWST To B/A Blender Ctrl) Closed 2NV-312A (Chrg Line Cont Isol) Open 2NV-3148 (Chrg Line Cont Isol) Open 2NV-294 (NV Pmps A & B Disch Flow Ctrl)- Open E. Auxiliary Feedwater System (CA) Aligned position 2CA-149 (S/G 2A CF Byp To CA Nozzle) 2CA-150 Closed (S/G 28 CF Byp To CA Nozzle) Closed 2CA-151 (S/G 2C CF Byp To CA Nozzle) 2CA-152 Closed (S/G 2D CF Byp To CA Nozzle) Closed F. Main Feedwater System (CF) Aligned Position 2CF-28 (S/G 2A CF Ctrl) 2CF-30 Closed (S/G 2A CF Byp Ctrl) Closed 2CF-33 2CF-37 (S/G 2A CF Cont Isol) Closed (S/G 2B CF Ctrl) Closed 2CF-39 (S/G 2B CF Byp Ctrl) 2CF-42 Closed 2CF-46 (S/G 2B CF Cont Isol) Closed (S/G 2C CF Ctrl) Closed 2CF-48 (S/G 2C CF Byp Ctrl) 2CF-51 Closed (S/G 2C CF Cont Isol) Closed

    ~.         . 2CF-SS         (S/G 20 CF Ctrl) 2CF-57                                                Closed (S/G 2D CF Byp Ctrl)                     Closed 2CF-60 2CF-87 (S/G 2D CF Cont Isol)                    Closed (S/G 20 CF Cont Isol Byp)                Closed 2CF-88        (S/G 2C CF Cont Isol Byp) 2C F-89                                                Closed (S/G 2B CF Cont Isol Byp)                Closed 2CF-90        (S/G 2A CF Cont Isol Byp)                Closed
  .       G.

Main Steam (SM) Alioned Position 2SM-1 (S/G 2D SM Isol & Byp Reset) 2SM-3 Closed (S/G 2C SM Isol) Closed 2SM-5 (S/G 2B SM Isol) Closed 2SM-7 (S/G 2A SM Isol) Closed 2SM-9 (S/G 2D SM Isol Byp) 2SM-10 Closed (S/G 2C SM Isol Byp) Closed 2SM-11 (S/G 2B SM Isol Byp) 2SM-12 Closed (S/G 2A SM Isol Byp) Closed H. Main Steam Vent to Atmosphere (SV) Aligned Position 2SV-1 (SM 2D PORV) 2SV-7 Closed (SM 2C PORV) Closed 2SV-13 (SM 28 PORV) 2SV-19 Closed (SM 2A PORV) Closed

 ,      Appendix A      ',,,                        3 2SV-25    (SM 20 PORV Isol)                            Open 2SV-26    (SM 2C PORV Isol)                            Open 2SV-28    (SM 2B PORV Isol)                            Open 2SV-27    (SM 2A PORV Isol)                            Open I.      Spent Fuel Cooling System (KF)                   Aligned Position 2KF-102B (FWST To Spent Fuel Pool)                      Closed 2KF-103A (FWST To Spent Fuel Pool)                     Closed J. Safety Injection (NI)                            Aligned Position 2NI-242B (UHI Accum Isol)                              Closed 2NI-242B Gag Inserted 2NI-243A (UHI Accum Isol)                              Closed 2NI-243A Gag Inserted 2NI-244B (UHI Accum Isol)                              Closed 2NI-2448 Gag Inserted 2NI-245A (UHI Accum Isol)                              Closed 2NI-245A Gag Inserted These valves will close when power is restored to them.

Aligned Position

           '~

2NI-54A (C-Leg Accum A Disch Isol) 2NI 65B Closed (C-Leg Accum B Disch Isol) Closed 2NI-76A (C-Leg Accum C Disch Isol) 2NI-88B Closed (C-Leg Accum D Disch Isol) Closed K. Reactor Coolant System (NC) Aligned Position

     .        2NC-27     (P:r Spray Ctrl From Loop A)                Closed 2NC-29    (Pzr Spray Ctrl From Loop B)                 Closed l

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