ML041600358

NRC Resolution of Licensee Comments

ML041600358
Person / Time
Site:	Oyster Creek
Issue date:	04/19/2004
From:	Caruso J NRC/RGN-I/DRS/OSB
To:	Conte R NRC/RGN-I/DRS/OSB
Conte R
References
50-219/04-301
Download: ML041600358 (48)

Text

ATTACHMENT 2 NRC RESOLUTION OF LICENSEE COMMENTS Licensees Post Written Examination Comments Publically Available in ADAMS Accession No. ML041380178 Note: During the exam there were no questions from the applicants regarding any of the 12 contested questions. The licensees first set of post exam comments regarding these twelve questions was received by the NRC on April 29, 2004. On May 11, 2004, the Region I staff discussed the NRCs preliminary resolutions of these comments. On May 14, 2004, the licensee resubmitted revised comments on all twelve of these originally submitted comments.

Question: RO 19 Given the following conditions:

• A Loss of Offsite Power has occurred

• Reactor is at rated temperature and pressure

• The drywell pressure entry condition for EMG-3200-02, Primary Containment Control has been satisfied.

• Reactor water level is 0" TAFand decreasing.

• You are operating all available DW cooling .

• The CRS asks: Can bulk drywell temperature be maintained below 150 degrees F?

• Your response is NO.

What is the basis for this response?

A. A LOCA signal has caused Chilled Water to isolate.

B. A High Drywell Pressure signal has caused Drywell Recirc fans to trip.

C. A LOCA signal has caused RBCCW isolation valves to isolate.

D. The rated capacity of 5 Drywell Recirc fans is inadequate.

ANSWER: C.

Question History Comment on original draft: Change All available drywell cooling to available drywell cooling based on confusion with SP-27 (incorporated)

Comment on 1/06/04 Change answers so only C is correct (incorporated)

Comment March 2004 Change answer B to Drywell Recirc Fans; change High Drywell Pressure to LOCA signal (incorporated). A final change in late March was made to the question stem to add the term all in order to be specific that all available fans would be running (that is, that the 5th fan had been started).

2 Licensee Comment:

The question asks:

Given the following conditions:

• A loss of offsite power has occurred

• Reactor is at rated temperature and pressure

• The drywell pressure entry condition for EMG-3200.02, Primary Containment Control has been satisfied

• Reactor water level is 0 TAF and decreasing

• You are operating all available DW cooling

• The CRS asks: Can bulk drywell temperature be maintained below 150 degrees F?

• Your response is NO What is the basis for this response?

The intent of the question as written was for the candidate to determine that a LOCA had caused RBCCW cooling to the drywell to isolate, therefore, triggering the response that drywell temperature could not be maintained below 150 deg. F based upon the loss of drywell cooling.

The third and fourth bullets above derive this. In this case, the candidate will choose answer C.

However, the wording of the fifth bullet is the exact wording used in a particular step of the Drywell Temperature leg of Primary Containment Control. Since the candidates had a copy of the Primary Containment Control EOP, and given the wording contained within the quotation marks, some of the candidates went directly to the step in the Drywell Temperature leg containing the wording Operate all available drywell cooling. This step directs the operator to bypass the RBCCW isolation signals and start all available drywell recirc fans. The logic the candidates used was

1. The information was in quotation marks, so it was therefore important to the answer

2. The only applicable step in Drywell Temperature that contains this specific wording is the step directing RBCCW isolations to be bypassed and all available drywell cooling (fans and RBCCW flow to the coolers) to be operated

3. Therefore, Support Procedure 27 has already been completed and RBCCW isolations have been defeated. Otherwise, this specific wording would not have been used in the question.

Based upon the above logic, the candidate would choose answer D which says the rated capacity of five drywell recirc fans is inadequate.

If the wording of the fifth bullet simply stated all drywell recirc fans are running, and nothing was contained in quotation marks, the candidates could not apply the above logic, and the only correct answer could be C.

Therefore, since there is no time line given for the LOCA event, and given the question construction, answers C and D are correct.

Oyster Creek recommendation: Accept C and D

3

References:

EMG-3200.02, Primary Containment Control (sent previously)

EOP Users Guide, pp. 2-14 through 2-16 (sent previously)

SP-27 Maximizing Drywell Cooling NRC Resolution:

Background Information: The Primary Containment Control emergency operating procedure (EOP) is entered upon drywell pressure exceeding 3.0 psig (stem condition). The RPV Control-No ATWS EOP is entered when Reactor Pressure Vessel (RPV) water level is less than 138" above Top of Active Fuel (TAF). The pressure leg and drywell temperature legs of the Primary Containment Control EOP are denoted with branching lines. Therefore, as specified in EOP Users Guide (page I-9) these legs and steps are intended to be performed concurrently. In this case, the operator will observe in the Pressure leg (from stem conditions that drywell pressure is high and RPV water level is at 0" TAF and decreasing) that containment isolation should have occurred and will proceed with the remaining steps in this leg. In parallel, the operator will enter the Drywell Temperature leg and will Monitor bulk drywell temperature...

The applicants should have determined that answer choice C was correct for the following reasons:

1) The applicants were provided the EOP flow charts, which provided them the necessary information to determine that RBCCW should have isolated based on the stem question reactor water level is at 0" TAF and decreasing. RPV Control - No ATWS (EMG-3200.01A) should have been entered on low reactor vessel level, Water Level leg NOTE states, RBCCW Isolation will occur if RPV level drops to 61".

2) EOP Users Guide, page 2-16 specifies that RBCCW System isolates upon the occurrence of either of the following conditions: Lo-Lo RPV water level (90" TAF) and high Drywell pressure (3.0 psig) OR Lo-Lo-Lo RPV Water Level (65" TAF). The question stem conditions of 0" TAF and Drywell pressure entry conditions for EMG-3200-02 satisfy these isolation criteria.

3) EOP Users guide page 2-14 specifies that Under most circumstances, maintaining the required number of Drywell recirculation fans in operation, maintaining Drywell instrument nitrogen/air to support operation of the Drywell recirculation fan dampers, and maintaining a sufficient flow of cooling water to the Drywell coolers prevents excessive Drywell temperatures. Given that all of the Drywell coolers should be operating at this point to maintain temperature below 150F, the flow of cooling water to the Drywell coolers must be insufficient to prevent excessive Drywell temperatures (i.e., RBCCW has isolated). Given these conditions, applicants with fundamental knowledge of the system and EOP procedures should have determined that answer C is correct (i.e., RBCCW had isolated from the Drywell coolers).

From the given stem condition, you are operating all available DW cooling, the applicant should have determined that all five Drywell cooling fans were operating or should have been operating based on knowledge of the following procedural guidance. The first two steps of Primary Containment Control EOP (Drywell temperature leg) would have the operator monitor bulk drywell temperature and operate available drywell coolers (recirc fans). During normal plant operations only four of the five Drywell coolers are operated and the fifth Drywell cooler

4 (1-3) is maintained in a standby status. The fifth fan would be started only as required to substitute for one of the operating fans or if required for supplemental cooling of the drywell.

The EOP users guide, 2000-BAS-3200.02, Revision 4, page 2-14 specifies Procedure 312.9 will be used to Maintain Bulk Drywell Temperature below 150 degrees F using available drywell coolers. Step 8.3.1.3 of Procedure 312.9, Primary Containment Control, Revision 29 specifies IF required for Drywell temperature control THEN START the 1-3 Drywell Recirculation fan.... At this point (after completing the second step) there should be five Drywell cooling fans running based on the guidance provided in Procedure 312.9. This is plausible when initially implementing EOPs and satisfies the given stem condition you are operating all available DW cooling.

The licensee stated that the basis for accepting answer D is that the wording of the stem condition, You are operating all available drywell cooling is quoting the fifth bullet in Drywell Temperature leg of the Primary Containment EOP and therefore the applicants were mislead to believe SP-27 (Support Procedure-27, Maximizing Drywell Cooling, Revision 16) had already been performed. There are several problems with this logic:

1) This is not a verbatim quote of the entire EOP step as written, the step reads, Operate all available drywell cooling per Support Procedure - 27". The stem did not include the wording in the last part of the this step ...per Support Procedure-27". It is unreasonable for the applicant to conclude RBCCW had been re-established without clear indication that SP-27 had been completed.

2) Since the stem does not specifically state nor imply that SP-27 has already been performed, the applicants had to make an assumption, that SP-27 had already been performed, and a subsequent re-entry condition existed causing a re-entry to Primary Containment Control. Therefore, the two (of eight) applicants that made this choice had to read into the question to make this assumption. NUREG-1021, Appendix E instructs the applicants, When answering a question, do not make assumptions regarding conditions that are not specified in the question.... By assuming that all available DW cooling meant they had already used SP-27, the applicants had gone beyond the information provided in the question stem.

3) With regard to the term All available DW cooling, it would be reasonable for the operator to recognize that he/she would normally only be operating 4 drywell recirc fans and that the fifth fan could have been started to satisfy the term all available as previously explained under normal operations or in response to these conditions. As noted above the given condition is plausible when initially implementing EOPs.

4) The preceding fourth bullet in Drywell Temperature leg is quoted verbatim in the question stem, Can bulk drywell temperature be maintained below 150 degrees F? and the answer to this question is also provided in the question stem, NO. The applicants should have recognized that there was no heat sink for the operating drywell recirc fans (i.e., that RBCCW had isolated from the recirc fans due to the isolation signals present).

5) In order to select answer D (i.e., The rated capacity of 5 drywell recirc fans is inadequate), the applicant would have to mis-apply the requirements SP-27. The prerequisite to SP-27 is The operation of all available drywell coolers has been directed

5 by the Emergency Operating Procedures AND the RBCCW system is NOT isolated due to a LOCA or MSLB in the drywell. Procedure step 2.2 states, IF the RBCCW System is isolated due to high Drywell pressure/low RPV water level, THEN inform the LOS and do not attempt to reinitiate the RBCCW System flow to the Drywell. The applicant should have determined based on the stated stem conditions in the question (i.e., high Drywell pressure and low RPV water level) that reinitiating RBCCW flow is prohibited by procedure. A CAUTION at Step 2.1 of SP-27 specifies Reinitiating RBCCW flow to the Drywell following a LOCA or MSLB in the Drywell may cause a water hammer to occur and subsequent piping failure. In order to assume that SP-27 had already been performed, the applicants would have had to disregard the conditions provided in stem, which prohibited reinitiating RBCCW flow. Although, SP-27 was not provided as a reference during the exam, the applicant should have been familiar with the prerequisites and the basic limitations of this procedure, which prohibited reinitiating RBCCW flow under these conditions.

After completing the first two EOP steps the question is asked Can bulk drywell temperature be maintained below 150 degrees F? If the response to this is NO, then the operator will proceed to the third step that says: Operate all available DW Cooling per Support Procedure 27". With RBCCW isolated from the drywell coolers there is no mechanism for heat removal from the drywell even though drywell recirc fans may be operating. The direction to use SP-27 is contained after the question can drywell temperature be maintained less than 150 degrees F. An applicant who understands the operation of the drywell cooling system, the EOPs, and the limitations of Support Procedure 27 should have picked C as the correct answer.

In conclusion, the NRC Staff does accept the licensees comment to accept both C and D as correct answers, C is the only correct answer to this question.

Distractor A is incorrect since there is no chilled water supplied to the drywell recirc fans.

Distractor B is incorrect since there is no direct trip of the drywell recirc fans on LOCA.

Distractor D is incorrect since the stem conditions, EOPs and SP-27 support the determination that the RBCCW is isolated and, thus, for these conditions the proximate cause of the elevated drywell temperature for this point in the EOP implementation is RBCCW being isolated.

Applicants would have to assume conditions not stated in the stem ( i.e., SP-27 had already been performed).

Question: RO 23 Given the following plant conditions:

• Reactor is at 100% power

• AOG is in service

• Main Steam Line Radiation Monitors all at approximately 550 mr/hr

6

• Stack Effluent HI alarm

• Reactor Bldg Vent Radiation at 8 mr/hr

• RCS activity at 90% of TS limit

• B IC isolated for maintenance

• Significant/visible packing leak from A IC outboard steam isolation valve

• NO leaks in the A IC tube bundle What action(s) would result in having the greatest reduction in the thyroid damage for the public?

A. Close A IC outboard steam isolation valve B. Reduce reactor power until stack effluent HI alarm clears C. Start SGTS and shutdown Reactor Building HVAC D. Close A IC vent valve ANSWER: C Question History Comment on original draft If power is < 40% AOG will be off. Changed to 100% power No additional technical comments after 12/03. Licensee made post-exam technical comments.

Licensee Comment:

The question asks:

Given the following plant conditions:

• Reactor is at 100% power

• AOG is in service

• Main Steam Line Radiation Monitors are all at approximately 550 mr/hr

• Stack Effluent Hi alarm

• Reactor Building Vent Radiation at 8 mr/hr

• RCS activity at 90% of TS limit

• B IC isolated for maintenance

• Significant/visible packing leak from A IC outboard steam isolation valve

• NO leaks in the A IC tube bundle What action(s) would result in having the greatest reduction in the thyroid damage for the public?

The intent of the question as written was to recognize plant conditions which would require a decision to secure normal Reactor Building ventilation and initiate Standby Gas.

The question construction forces the candidate to evaluate all plant conditions presented in the bullets for any conditions that will govern entry into EOPs, ABNs, and RAPs. This is a logical thought process all candidates go through when presented with numerous, significant plant

7 conditions. They are conditioned to look for those parameters which will force entry into various procedures.

The plant conditions are below the threshold entry conditions for Secondary Containment Control (vent radiation monitors at or above 9 mr/hr).

However, the plant conditions presented will dictate actions in accordance with ABN-26, High Main Steamline or Offgas Activity. The applicability for entry into this procedure is Main Steam radiation levels 550 to 800 mr/hr. Also, RAP 10F-2-d, Stack Effluent HI, directs actions in accordance with ABN-26.

In Section 3.3 of ABN-26, the following actions are directed:

1. If reactor power is greater than 40% and off gas activity rises by more than 50% after factoring out any rise due to changes in thermal power, then direct chemistry to sample off gas and the reactor coolant, refer to Tech Specs 3.6.E and 4.6.E, and request guidance from reactor engineering.

2. If any of the following alarms are received (off gas hi (10F-2-c), stack effluent hi (10F d) or stack effluent hi-hi (10F-1-d)), then review recent changes in offgas flow, condenser vacuum, steam seal header pressure, notify chemistry of the condition, reduce reactor power until all three radiation alarms have cleared. If all three radiation alarms cannot be cleared, then direct chemistry to sample the reactor coolant and off gas.

Our position is that answers B and C are both correct, depending upon how the candidate interpreted the presented plant conditions. If the candidate assessed the conditions as to what procedurally-directed actions are required, then reducing reactor power until the stack effluent HI alarm clears is a correct statement (B). If the candidate assessed the conditions and determined it is necessary to take actions based upon their judgment to initiate an engineered safeguard system (even though it is not specifically directed by plant procedures,) then starting SGTS and securing Reactor Building HVAC is a correct statement (C).

Based upon the presented plant conditions and recognition by the candidate that an entry condition to ABN-26 has been met, the only action procedurally dictated by these plant conditions is to reduce reactor power until [all three radiation alarms] the Stack Effluent Hi alarm clears. This is answer B.

The suggested answer (C), to start SGTS and shutdown Reactor Building HVAC, forces the candidate to forego procedurally dictated actions for the existing plant conditions, and make a decision to operate SGTS in order to filter the reactor building atmosphere through SGTS before being sent to the plant stack.

Procedure OP-OC-100, Oyster Creek Conduct of Operations, sections 5.1.1 and 5.1.2 gives SROs as well as ROs the authority to initiate an engineered safeguard system when, in their judgment a situation exists which jeopardizes or threatensto jeopardize public or plant safety.

All licensed operators (ROs and SROs) are trained to recognize entry conditions into ABNs, and when entry conditions are present, to execute the appropriate ABN even if not specifically ordered to do so by the Unit Supervisor. Additionally, it is the RO who will be referred to ABN-26

8 from the Stack Effluent Hi alarm RAP. Reactor Operators have learning objectives dealing with identification of procedures used during abnormal conditions. Specifically:

1. (L.O. #1406) Assess given plant conditions, reports or control room indications and determine if an abnormal operating procedure (ABN) applies without the aid of references.

2. (L.O. #1407) Evaluate plant conditions during a transient and determine which (if any) abnormal operating procedure (ABN) is applicable.

Based upon our learning objectives and our Conduct of Operations, this question pertains to both Reactor Operators as well as Senior Reactor Operators.

In our judgment, this question is written to give specific procedural entry conditions, but then requires the candidate to forego the procedural guidance if he was to choose the suggested correct answer. We have trained the operators to execute approved procedures when they are applicable. Instead of supplying specific plant conditions in the question stem and expecting the candidate to choose a general course of action, it would be more appropriate to word the question in general terms in order to preclude this inherent conflict the question presented.

Therefore, answers B and C are correct.

Oyster Creek recommendation: Accept B and C

References:

RAP 10F-2-d, STACK EFFLUENT HI (sent previously)

ABN-26, High Main Steam Line or Off-Gas Activity (sent previously)

OP-OC-100 Oyster Creek Conduct of Operations NRC Resolution:

The question asked what should be done to give the greatest reduction in thyroid dose. It did NOT ask what should be done in accordance with ABN-26, High Main Steam Line or Off Gas Activity, Revision 0. The question was written to be a Higher Cognitive Level question, and was designed to have the applicants think beyond the prescripted information in the ABN and to understand the source of the thyroid dose, and how best to reduce it. The question was designed to test the knowledge of the operational implications of the biological effects of radioactive ingestion as it applies to Off Gas Release rate (i.e., in this case a release of radioactive iodine).

The question asks, What action(s) would result in having the greatest reduction in thyroid dose. Answer choice C is the correct answer for the following reasons:

1) The conditions in the stem indicates that the major source of radioactive iodine being released to the public is via the reactor building ventilation, (Significant/visible packing leak from A IC outboard steam isolation valve). As documented in the Secondary Containment and SGTS Lesson Plan (2611PGD-2601), Revision 08 (section I.3) states that the design basis of SGTS is to Limit the release of radioactive material; to the plant environs to less than 10 CFR 100 limits. It goes on to specify (on page 22) that the

9 charcoal absorbers in SGTS are Provided to remove iodine from the air flow and is designed to accomplish a 99.9% removal.

2) Section 4.3 of Procedure 330, Standby Gas Treatment System, Revision 40 provides instructions for a Manual Startup of Standby Gas Treatment System. A review of prerequisites and precautions in this section revealed NO restrictions on operating SGTS during the stated question stem conditions.

3) The Oyster Creek Conduct of Operations procedure, OP-OC-100, Revision 0, section 5.0, step 5.1.1 states in part, The responsible Operations Supervisor (SRO licensed) has the duty and authority ....initiate an engineered safeguard system under the following circumstances: When in their judgement a situation exists which jeopardizes or threatens to jeopardize public or plant safety. Furthermore, procedure step 5.1.2 states, On-shift Reactor Operators have the duty and authority to ....initiate an engineered safeguard system under the following circumstances: When in their judgement a situation exists which jeopardizes or threatens to jeopardize public or plant safety.

4) Given the stem conditions and the function of SGTS is to remove radioactive iodine from the reactor building atmosphere, both RO and SRO applicants should have considered the direction in the Conduct of Operations procedure, anticipated worsening radiological release conditions from the leaking IC steam valve to the Reactor Building, taken action to shutdown RBHVAC, and to manually start SGTS. In this case, isolating the Reactor Building Vent system and starting SGTS would limit radioactivity release from the Secondary Containment (purpose of Secondary Containment Control as specified in the EOP Users Guide, page 11-1). This is the action specified in answer C. In addition, the licensee re-evaluated the validity of correct answer choice C again and concluded that starting SGTS and securing Reactor Building HVAC is a correct statement (C).

The licensee stated, If the candidate assessed the conditions as to what procedurally-directed actions are required, then reducing reactor power until the stack effluent HI alarm clears then answer choice B is correct. There are several problems with this logic:

1) The question asks, What action(s) would result in having the greatest reduction in thyroid dose. Reducing power will decrease Iodine production but the inventory of radioactive iodine already in the RCS will continue to be released even after power level is reduced. The half life of I-131 is approximately 8 days, not minutes or even hours.

Therefore, reducing reactor power, albeit provided as action in ABN-26 for steam line or stack gas activity, will not provide the greatest reduction in offsite thyroid dose when compared to the effect of starting SGTS, therefore, reducing power does not answer the question or mitigate the problem.

2) The question required the applicants to understand the limitations of both the normal AOG System, and ABN-26. Furthermore, the iodine released by the steam leak to the Reactor Building atmosphere (as posed in this question) will require operation of the SGTS to remove the released iodine from the steam leak before it is released. ABN-26 is focused on the Main Steam System and Off Gas, and is silent on the iodine release from the Reactor Building. The Augmented Off Gas (AOG) system (with its large

10 amount of charcoal) will absorb virtually all iodine input from the Steam Jet Air Ejectors (normal effluent path from the Main Steam System) regardless of power level but will do nothing to mitigate this problem. Furthermore, if the only action taken in response to the stem conditions was to reduce power the thyroid dose due to the release would NOT be mitigated for several days.

Knowledge of AOG system, reactor physics, and radiation protection should allow the applicant to understand that reducing power (albeit procedurally correct for the elevated main steam radiation) would have little effect on the thyroid dose to the public (generated by the steam leak in the reactor building). Therefore, reducing power (i.e., implementing ABN-26) does not answer the question and implementing this procedure will not mitigate the threat to public health and safety in any reasonable period of time. Additionally, the expected system knowledge of SGTS design bases and functions, SGTS System Operating Procedures and mitigation strategies, should allow an applicant to determine that answer C is the only technically correct answer.

In conclusion, the NRC Staff does accept the licensees comment to accept both B and C as correct answers, C is the only correct answer to this question.

Distractor A is incorrect since the packing leak will continue even with the valve closed. In addition, EOPs would NOT have you isolate a system needed to support any EOPs. ICs are used to support RPV Control. The B IC is out of service.

Distractor B although procedurally correct is incorrect since reducing power will not significantly reduce the thyroid dose to the public for several days following a power reduction due to the half life of the source term. The large amount of charcoal in the AOG will absorb virtually all iodine input from the Steam Jet Air Ejectors (effluent from the Main Steam System) regardless of power level but do nothing to mitigate a leak from a system discharging into the reactor building atmosphere.

Distractor D is incorrect since vent valves discharge to Main Steam Lines (not directly to the environment). These are normally closed (only open 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> in 44 days).

11 Question: RO 25 Following a loss of offsite power, the crew has initiated EMG-3200.01A RPV Control-No ATWS and is at the step that specifies Confirm the following sub-systems lined up for injection with pumps running.

Which of the following configurations of Core Spray annunciators LIT would confirm either Core Spray System 1 or Core Spray System 2 is lined up with pumps running?

A. SPARGER 1 DP HI, SYSTEM 1 FLOW PERMISSIVE, BSTR PUMP A/C OL B. SPARGER 1 DP HI, SYSTEM 2 FLOW PERMISSIVE, BSTR PUMP A/C OL C. SPARGER 2 DP HI, SYSTEM 2 FLOW PERMISSIVE, BSTR PUMP A/C OL D. SPARGER 2 DP HI, SYSTEM 2 FLOW PERMISSIVE, BSTR PUMP B/D OL ANSWER: B This Note: This was a closed reference question.

Question History Comment on original draft; Change stem to confirm the following subsystems lined up for injection and running. Change OL alarm terminology Comment 1/06/04 Change B to A/C OL, C should be A/C OL, D should be B/D OL (done)

No additional technical comments after 1/6/04. Licensee made post-exam technical comments.

Licensee Comment:

UFSAR sections 6.3.3.2.1 and 6.3.3.1.6 require the core spray injection line to be intact to meet ECCS design criteria. The design flow is through the injection line, to the ring headers and through the sparger nozzles to spray the top of the core inside the reactor vessel.

RAP B-5-e and B-5-f (sparger dp hi alarms), list the cause of the alarm as high differential pressure across the sparger nozzles due to Core Spray line break in the vessel annulus. With the alarm in, all core spray flow is diverted to the annulus.

Question 25 refers to a specific step within the Level Restoration procedure regarding confirmation of injection subsystem availability. That step in the EOPs does not address spray cooling effectiveness. It only addresses whether the listed injection subsystems can be relied upon to inject water into the vessel, not through the core spray sparger and, thus directly on top of the core. In the generic EPGs, spray cooling is not even addressed, since there is no confirmation of adequate core spray pattern following an accident. The EPGs only rely on core reflood in order to provide adequate core cooling. Adequate core cooling, as defined within the EPGs, is adequate heat removal to preclude cladding temperatures from exceeding 1500 degrees F, the threshold for cladding perforations.

12 Oyster Creek (BWR-2 design) has taken a deviation from the generic EPGs, due to the plant design. BWR-2 design will preclude the possibility of reflooding the core region, due to the recirculation piping penetrations in the vessel lower head. Since the BWR-2 cannot be reflooded to 2/3 core height (as in the BWR-3 through 6 product lines), we added an additional set of steps further on in the Level Restoration procedure that addresses adequate core spray cooling, per the plant design basis. In this particular case, the plant would have already been emergency depressurized, and all actions to restore and maintain water level above -30 inches would have been attempted. In the event level cannot be restored and maintained above -30 inches, even after all the mitigation strategies of Level Restoration have been exhausted, the Oyster Creek EOPs will direct one last effort to provide adequate core cooling by asking whether the core spray systems are injecting at design basis flows. At this point in the EOPs, we are taking credit for the plant design basis of limiting cladding temperature below 2200 deg.

F, the threshold for accelerated zirc-water reaction. When the question of core spray injection at design basis flow is finally addressed, any problems with the core spray spargers would invalidate the affected core spray system, and the eventual outcome would direct exit from the EOPs and entry into the SAMGs.

The question stem does not address core spray operation at design basis flow (which is one of the last steps within Level Restoration.) The stem is asking about injection subsystem availability, which only addresses RPV vessel injection capability, not design basis core spray flow through the spray headers. Therefore, sparger dp concerns has no bearing on the answer to this question.

Based upon the above, all four answers were assessed without any regard to sparger dp alarms.

For the remaining information in the question, the key to determining which set of conditions will result in core spray flow is the Flow Permissive signal. Per RAP B-2-e and B-2-f (SYSTEM 1/2 FLOW PERMISSIVE), the following conditions must be met:

• Booster pump dp signal for the respective core spray system, AND

• Core spray main pump discharge pressure, AND

• RPV pressure less than 305 psig Based upon these criteria, answers A and D CANNOT be correct, as the booster pump overload trip affects its system, and the booster pump dp signal will NOT be generated, thereby eliminating the flow permissive signal for that system. However, answers B and C are both correct, as the booster pump trip affects the other system, allowing the flow permissive alarm to be received and satisfying the question stem condition that ..sub-systems are lined up for injection with pumps running.

Therefore, answers B and C are correct.

Oyster Creek recommendation: Accept B and C

References:

RAP B-2-e, SYSTEM 1 FLOW PERMISSIVE (sent previously)

RAP B-3-e, BSTR PUMP A/C OL (sent previously)

RAP B-5-e, SPARGER 1 DP HI (sent previously)

13 RAP B-2-f, SYSTEM 2 FLOW PERMISSIVE (sent previously)

RAP B-3-f, BSTR PUMP B/D OL (sent previously)

RAP B-5-f, SPARGER 2 DP HI (sent previously)

EMG-3200.01A, RPV Control - No ATWS, Level Restoration (sent previously)

EOP Users Guide, pp. 1A-25 and 1A-39 (sent previously)

NRC Resolution:

The NRC staff reviewed EOP EMG-3200.01A, RPV Control- No ATWS, Revision 4 to determine the requirements of the steps in the Water Level leg. The fourth step in the Level Restoration sequence requires the operators to confirm the following sub-systems lined up for injection with pumps running . In accordance with the EOP Users Guide, page 1A-25, The purpose of this step is to maximize the injection capability of the RPV injection subsystems.

This is accomplished by confirming the correct system lineup, aligning the system for maximum flow, and confirming the pumps are running in accordance with the applicable Support Procedure (in the case of Core Spray, Support Procedure 9, Lineup for Core Spray System Injection, Revision 11). The question required the applicant to determine, based on alarm status, which Core Spray Sub-Systems satisfied the criteria of being lined up with pumps running, which is different criteria from Is The Core Spray System Operating At Design Basis Flow? (discussed below).

Core Spray System 1 uses Core Spray Pumps A and C as well as Core Spray Booster Pumps A and C. Core Spray System 2 uses Core Spray Pumps B and D as well as Core Spray Booster pumps B and D. In order to consider a sub-system ...lined up for injection with pumps running there must be at least one Core Spray Pump and one Booster pump running in that sub-system.

Each answer specified either a SYSTEM 1or SYSTEM 2 FLOW PERMISSIVE alarm LIT. The response procedure for these alarms (RAP B-2-e/B-2-f, Revision 130) specify that the alarm is LIT if Booster Pump differential pressure greater than 30.5/28.5 psid AND Core Spray Pump discharge pressure greater than 100 psig AND Reactor Pressure less than 305 psig A note in RAP B-2-e (B-2-f) specifies This alarm will actuate only if all three conditions are met indicating that core spray should be injecting into the depressurized Rx core. Therefore, the presence of this alarm (for the particular sub-system) would indicate at least one core spray and one booster pump in that sub-system are, indeed running.

Each of the answers contains a condition that a SPARGER DP HI alarm is LIT. It was originally thought that this alarm being LIT would indicate to the operator that the sub-system would NOT be available for injection. Thus, answer B was thought to be the (only) correct answer. A review of SP-9 revealed NO mention of the SPARGER DP HI alarm. The licensee contends that the presence of this alarm would NOT result in the operator concluding the system was unavailable for injection. This contention is supported by our review of the EOP, SP and EOP Users Guide. That is, with a SPARGER DP HI alarm LIT the operator would still consider the system lined up for injection with pumps running as long as the associated SYSTEM 1(2) FLOW PERMISSIVE alarm is LIT. Therefore, even with the SPARGER DP HI alarm LIT, either subsystem satisfies the criteria of ...lined up for injection with pumps running.

14 The alarm response for the BSTR PUMP A/C (B/D) OL (RAP B-3-e/B-3-f, Revision 130) provides direction to Start alternate pump as required and trip the affected pump. Any subsystem with this alarm LIT would indicate to the operator that any running booster pump in that subsystem is degraded and must be tripped. In this condition, the affected sub-system would NOT satisfy the requirement that the sub-system is ...lined up for injection with pumps running For the stem conditions and distractors provided, System 1 does have the associated BSTR PUMP A/C OL alarm LIT, and therefore would NOT satisfy the criteria of pumps running.

System 2 does NOT have the associated BSTR PUMP B/D OL alarm LIT and therefore would satisfy the criteria of pumps running.

Answer B and C each provide a set of alarms for System 2 that satisfies the criteria of being

...lined up for injection with pumps running. Based on the preceding information, it is reasonable for the operator to select either B or C as a correct answer since both of these satisfy the criteria of lined up with pumps running.

It should be noted (as discussed in the licensees comment) an additional set of steps further on in the Level Restoration portion of this EOP procedure specifically addresses adequate core spray. In this particular case, the plant would have already been emergency depressurized, and all actions to restore and maintain water level would have been attempted. At this point, the Oyster Creek EOPs direct one last effort to provide adequate core cooling by asking, Is The Core Spray System Operating At Design Basis Flow? In this case, the presence of the sparger DP alarm should result in a NO answer, since it cannot be determined whether design basis flow would be met with this alarm present. The response to the NO answer would be to line up injection and start pumps and maximize injection with alternate sub-systems in order to ensure adequate core cooling. Note: The FSAR, sections 6.3.3.1.1 and 6.3.3.1.5 state that tests were run as low as 3,100 gpm and as high as 4,500 gpm and the minimum design flow of 2.45 gpm per bundle which was established as the design basis was achieved across the core with of either of these flow rates. In summary, it would take only one intact Core Spray System (loop) to meet design basis flow, since System 1 flow rate is 3,400 gpm and System flow rate is 3,600 gpm.

In conclusion, the NRC Staff accepts the licensees comment. B and C should be considered correct answers.

Distractor A is wrong since the associated Booster pump for Core Spray sub-system 1 is unavailable (BSTR PUMP A/C OL) alarm lit.

Distractor D is wrong since the associated Booster pump for Core Spray sub-system 2 is unavailable (BSTR PUMP B/D OL) alarm lit.

Question: RO 37 Following a rod drifting in, the RWM will relatch.

15 RMCS will locate the highest completed step that meets which one of the following criteria?

A. LESS THAN three insert errors and MORE THAN two rods are withdrawn past the insert limit.

B. NO insert errors and AT LEAST one rod is withdrawn past the insert limit C. LESS THAN three insert errors and AT LEAST one rod withdrawn past the insert limit.

D. NO insert errors and NO withdraw errors ANSWER: C Note: This was closed reference question.

Comment History This was an OC bank question. No technical comments from original draft through final issue.

Licensee made post-exam technical comments.

Licensee Comment:

Per RAP H-6-A, ROD DRIFT, the cause is any control rod drifting more than 3 through an odd rod position, when the control rod is not selected. The RAP directs a scram if more than one rod is moving in or out abnormally. If only one rod is moving, it directs actions in accordance with ABN-6, Control Rod Drive System.

The action to select a control rod is not governed by procedure, because it is expected that the operator knows to turn on Rod Power and depress the associated push button on the rod select display. For a rod drift, if the correct rod is selected and the rod drift alarm clears, that is definitive evidence that only one control rod is drifting, as the rod drift alarm only alarms if a rods odd reed switch is picked up and the rod is not selected. Selecting the rod to diagnose the drifting condition aids the operator in determining if more than one rod is drifting (due to the rod drift alarm not clearing when the drifting rod is selected), which will dictate a reactor scram IAW RAP H-6-a for multiple rods drifting. Within that RAP, the operator actions (manual corrective actions) dictate a determination whether more than one rod is drifting. If only one rod is drifting, then the RAP sends the operator to ABN-6 for further instructions. If the operator selects a different rod (i.e., one that is NOT drifting), the consequence of this action is immaterial, in that the selected rod will not move until the operator applies a movement signal to it. Therefore, selecting the rod is entirely within the guidance of User Capability as defined in HU-AA-104-101.

Procedure HU-AA-104-101 (revision 0), Procedure Usage and Adherence, section 4.6 addresses actions called User Capability (skill of the craft.) It stipulates that actions may be performed by trained, qualified individuals as User Capability without a procedure provided that:

16

• No procedure exists for the action and

• The task is simple, short, and routine where the consequences of improper performance are not significant.

Per the RWM tech manual (VM-RW-1316), on page 20 of 42, section 3.11.1, . . . The rod drift signal explicitly defines to CRMS [Reactor Manual Controls] that a full core scan and rod block requests are to be made if the rod drift has not cleared within a T1 time period. Additionally, a second full core scan request is to be made after the drift has been clear for a T2 period of time and the first full core scan has been completed. The timer offsets are described on page 11 of 39 of the detailed design manual, which was also provided in the original submittal.

Timer T1 is a 10 second offset for the rod drift to clear.

Timer T2 is a 10 second offset for the rod drift to remain clear.

In the event the operator does not select the drifting rod within the first 10 seconds, timer T1 will time out, which will call for a full core scan. This will result in the RWM latching to a previously completed step, and will show the drifted rod as an error. If the rod is notselected within the first 20 seconds of the drift, a second full core scan will then be made, subsequent to the T2 timer timing out. This will result in selecting answer C.

If, however, the operator selects the drifting rod within the first 10 seconds, timers T1 and T2 will never time out. Therefore, the rod will be treated (within the RWM) as a slowly settling rod, and no errors will be generated. In this case, the only way an insert error will be detected is based upon a relatch signal being generated by the RWM. While the rod is selected, this scan will only occur when the RWM performs its periodic full core scan. Unless a full core scan is processed, the selection of the drifting control rod within the first 10 seconds of the drift will result in an initial latch showing NO insert errors and NO withdraw errors. The rod will subsequently be identified as an insert error whenever the next periodic core scan is completed. This will result in selecting answer D.

Since no time line is given within the question stem, answers C and D are correct as stated above.

Oyster Creek recommendation: Accept C and D

References:

Rod Worth Minimizer lesson plan (sent previously)

VM-RW-1316, RWM DETAILED DESIGN MANUAL, sections 3.5.2.3, 3.11.1, and 3.11.3.3 (sent previously)

ABN-6, Control Rod Drive System (sent previously)

RAP H-6-a, ROD DRIFT (sent previously)

HU-AA-104-101 Procedure Use and Adherence NRC Resolution:

Background information: The wording in the stem indicating the RWM will relatch connotes that the drifting rod has traveled far enough in to cause a ROD DRIFT alarm (otherwise the RWM would have no need to relatch). The term relatch is similar in meaning to reinitializing or resetting the system such that the system resets back to a pre-programmed rod pattern. The

17 set point for the ROD DRIFT alarm is actuation of odd numbered position switch on non-selected control rod. The OC Reactor Manual Control system provides rod position for all 137 rods. The operator can observe (real-time) the position of all 137 rods simultaneously.

However, the OC design (unlike most other BWRs) has no individual red ROD DRIFT or DRIFT lights at the reactor panel (Panel 4).

The NRC staff review confirmed that answer C (the designated answer) is correct. The references sent by the licensee as well as the RWM Lesson Plan \(2611-PGD-2621) confirmed that, A full core scan of control rod positions is requested by CRMS following a 10 second delay after the detection of a rod drift condition. If the operator does not select the drifting rod within 10 seconds the RWM will complete a core scan and detect the drifting rod as an insert error. As noted on page 10 of the RWM Lesson Plan When insert or withdrawal errors exist, CRMS finds the highest completed step such that: 1) less than three insert errors exist, and 2) at least one rod in step is withdrawn past the step insertion limit... . The licensees recommendation agrees with this conclusion that C is the correct answer given no operator action.

The licensee stated that the basis for accepting answer D is that the operators are trained to select a drifting rod for diagnosis purposes. There are several problems with this logic:

1) The stem of the question reads, Following a rod drifting in, the RWM will relatch.

RMCS will locate the highest completed step that meets which one of the following criteria? The stem does not specifically state nor imply that any operator action has been taken, therefore, the applicants had to make this assumption. NUREG-1021, Appendix E instructs the applicants, When answering a question, do not make assumptions regarding conditions that are not specified in the question.... The question was asking how the system was designed to respond following a rod drift without any operator action specified.

2) In order for D to be a correct answer, an operator would have to accomplish a scan of 137 rod positions including a review of additional incoming alarms and then take action to select the drifting rod in < 10 seconds, which would result in re-latch of the RWM with NO insert errors and NO withdraw errors. While the licensees assertion that the operators are trained to do this may be correct, no procedure guidance substantiates the selection of a drifting rod for diagnosis purposes. Neither ABN-6 nor any other procedure referenced provides this guidance.

3) The licensee has produced no evidence that this operator action could and/or would be expected to be completed in < 10 seconds.

In conclusion, the NRC Staff does not accept the licensees comment to accept both C and D as correct answers, C is the only correct answer to this question.

A is wrong since the RWM does not require two rods withdrawn past the insert limit.

B is wrong since the RWM does not require NO insert errors to relatch.

D is wrong because the question stem does not does not specifically state nor imply that any operator action has been taken; no procedure guidance substantiates the selection of a drifting

18 rod for diagnosis purposes; the licensee has produced no evidence that this operator action could and/or would be expected to be completed in < 10 seconds.

19 Question: RO 47 Given the following conditions:

• Immediately following a loss of all offsite power you are the reactor operator and observe one control rod at position 48 with the remaining control rods at 00.

• Ten seconds later both emergency buses are energized from Diesel Generators (EDGs).

Which of the following describes the affect on IRM/APRM indications?

A. Lose IRM/APRM indications due to loss of PSP-1&2.

B. Maintain IRM/APRM indications due to DC power supply available.

C. Lose IRM/APRM indication due to loss of vital buses and RPS MG set voltage.

D. Maintain IRM/APRM indications due to re-powered busses and RPS MG set flywheels.

Answer: B Note: This was closed reference question.

Question History Comment on initial draft,There is substantial power going to NIs. Need to research what you will have remaining. Comment 3/04, change question to What nuclear Instrument Indication will you have and why, also OC changed all answers to final form (provided by OC). Licensee made post-exam technical comments.

Licensee Comment:

The question asks:

Given the following conditions:

• Immediately following a loss of all offsite power you are the reactor operator and observe one control rod at position 48 with the remaining control rods at 00

• Ten seconds later both emergency buses are energized from diesel generators (EDGs)

Which of the following describes the affect on IRM/APRM indications?

Regarding the IRM/APRM circuitry and indications, the following sources of power exist:

• +/- 24 VDC, which powers the IRM and APRM detector circuitry as well as indications on the respective IRM and APRM drawers (Panels 3R and 5R) and IRM/APRM power indication on Panel 4F recorders. Battery chargers powered from IP-4 are the normal source, with the batteries as backup.

20

• CIP-3, which provides IRM and APRM recorder power on Panel 4F and IRM trip units for rod blocks and scrams. CIP-3 is powered from a rotary inverter. Normal power to the rotary inverter is an AC motor powered from VMCC 1B2, with a backup DC motor powered from DC-B. The rotary inverter is normal seeking and will shift back to the AC motor once steady power is restored to VMCC 1B2 for 2 minutes.

• RPS bus 1 and 2, which powers trip circuitry and RPS trip units associated with the respective APRM drawers, and power to the LPRMs. As long as the LPRMs have power, their inputs to the APRM drawers will reflect actual reactor power.

For RPS buses 1 and 2, the RPS MG set flywheels will maintain power long enough for the EDGs to start and re-power 1C and 1D buses. The basis for this is presented below.

In a memo dated January 11, 1996 regarding loss of RPS power during LOOP, the RPS engineer provided the following information. (Copy of memo is enclosed)

• Upon a loss of offsite power with a successful anticipatory scram, the RPS MG set output breaker and Electrical Protection Assemblies will trip on under-frequency or under-voltage in approximately 15 seconds.

• Upon a loss of offsite power with no anticipatory scram, the RPS MG set output breaker and EPAs will trip on under-frequency or under-voltage in approximately 4 seconds.

Based upon the question stem, a successful scram has occurred, therefore RPS MG set flywheels will maintain power to the RPS buses for up to 15 seconds. The information states the EDGs repower the 1C and 1D buses within 10 seconds of the power loss, so RPS is not lost during this transient.

Looking at the possible answers, neither answer A or answer C can be a correct statement.

Both of these answers address losing indications either due to loss of PSP-1 and 2 (RPS-1 and 2), or due to loss of vital buses and RPS MG set voltage. Since RPS MG set voltage is not lost during this transient, neither of these statements can be correct.

Answer B is a correct statement based upon the following. DC power supplies (+/- 24 VDC and DC-B for the CIP-3 drive motor) are available throughout the transient.

Answer D is a correct statement based upon the following. All vital buses will be re-powered when the EDG breakers close 10 seconds after the loss of offsite power. The RPS buses will never lose power due to the design of the RPS MG set flywheels.

Therefore, answers B and D are correct statements and IRM/APRM indications are maintained throughout the stated transient.

Oyster Creek recommendation: Accept B and D

References:

RAP 9XF-5-c, CIP-3 INV AC INP LOST (sent previously)

GPUN Memo 2252-96-001, dated January 11, 1996 (sent previously)

Background Information

21

1. The IRMs contain moveable miniature fission chambers that (through the use of amplifiers and signal conditioners) indicate reactor flux (power) from approximately.01% to 40% power.

The detectors are withdrawn during a start-up when power indicates in the power range. Upon SCRAM, the detectors are inserted into the core to provide an indication of the shutdown power level as power decays below APRM range.

2. APRMs receive their input from LPRMs (stationary miniature fission chambers). The LPRMs rely on 120 VAC from RPS for detector voltage. Each APRM drawer (back panel) receives input from multiple LPRMs. The APRM drawer processes these LPRM inputs to provide an indication of Reactor Power from 1% to 125% of full power. Each drawer has a meter to indicate reactor power. The APRM drawers are powered from 24 V DC (battery supplied). The output from the APRM drawer is transmitted to recorders on Panel 4F so the operator at the controls has indication and recording of reactor power.

3. Although the 480 V AC drive motor for the Reactor Protection System (RPS) MG set is lost during a loss of offsite power they are re-powered by the diesel generators. In the interim (while diesel generators are starting up) each RPS MG set has a flywheel that will maintain voltage for 4 to 15 seconds, depending on the RPS bus load. It was confirmed that the stem conditions would have indicated a SCRAM existed and, therefore the RPS buses would have minimum load. With minimum load on the RPS bus the GPUN Memo 2252-96-001, dated January 11, 1996 specifies the RPS Bus voltage (supplied to LPRMs, APRMs and Panels 3R and 5R meters) would be adequate to maintain these instruments functional for 15 seconds.

Since the stem condition provides that the diesel generators energize the emergency buses within 10 seconds, the power supply to the LPRMs, APRMs and Panels 3R and 5R (back panel) meters would not be interrupted.

NRC Resolution:

The NRC staff reviewed the documentation submitted as well as consulting other available technical documents, including the lesson plan (Nuclear Instrumentation, Revision 03). The following represent the results of our review IRM/APRM/LPRM Power Supplies:

1. 24 V DC

2. 120V AC RPS Bus

3. 208 V AC from CIP-3

4. 3 phase 120 VAC Vital Power (instrument panel 4)

During normal operation, all power supplies are energized as follows:

1. 24 V DC from a battery charger

2. 120 V AC RPS Bus from an MG Set powered from a 480 V AC Motor/120 V AC Generator

3. 208 V AC from an MG set (called rotary inverter) with 208 V AC generator driven by 480 V AC Motor (attached 125 V DC Motor deenergized)

4. 3 phase AC Power Vital AC from ESF Bus During a Loss of Offsite Power (LOOP) power supplies are energized as follows:

1. 24 V DC from a battery bank (uninterruppted)

2. 120 V AC RPS Bus from the MG set flywheel coastdown (4 to 15 seconds) then 480 V AC Motor repowered from Diesel Generators

• 22

3. 208 V AC from an MG set powered by 125 V DC Motor(uninterrupted)

4. 3 phase 120 VAC Vital Power (instrument panel 4) lost for 10 seconds and re-powered by diesel generators

• During the scenario described in the question the MG set flywheels are expected to maintain voltage on their respective RPS Buses until the diesels power-up the ESF buses IRM Power supplies required for accurate indication in control room:

1, 3, 4** (See above LOOP)

• • Although this is required to drive detectors in core the IRMs will still provide flux indication in the withdrawn position. The 10 second delay to drive the detectors in will have no impact on determining that the reactor is shutdown following a SCRAM APRM Power supplies required for accurate indication in control room 1, 2***, 3 (See above LOOP)

• • • Required for LPRM which are inputs to APRM Channels LPRM Power supplies required for accurate indication in control room 2 (See above LOOP)

Summary of power supply effects on IRM/APRM indication during the postulated exam question conditions: All IRM and APRM indication should remain functional during the exam question conditions. The issue is not a design power supply problem, rather it is an answer structure problem. That is, due to the structure of the provided answers the complete scope of power required and power available is not fully described in any one answer.

Effect on Answers A, B, C and D Distractor A is wrong since PSP-1 and 2 do not power up the IRM/APRM indicators.

Distractor C is wrong since the loss of the RPS MG will not affect the panel indicators.

AnswerB specifies Maintain IRM/APRM indications due to DC power supply available. This is a correct statement, although this answer is incomplete (does not include the 120 VAC from RPS Bus). Although, the answer is incomplete, the answer provides no conflicting and/or incorrect information for the stated question conditions and will be accepted.

Answer D, specifies Maintain IRM/APRM indications due to repowered buses and RPS MG set flywheels. This is also a correct statement, although this answer is incomplete (the IRM detectors and amplifiers as well as the APRM amplifiers require 24 V DC which is not a re-powered source and is not, therefore, included in this answer). Although, the answer is incomplete, the answer provides no conflicting and/or incorrect information for the stated question conditions and will be accepted. In conclusion, the NRC Staff accepts the licensees comment. B and D should be considered correct answers.

23 Question: RO 71 The following plant conditions exist:

• The reactor power has just been increased to 40% power

• Turbine-Generator is on the line at approximately 200 MWE

• A malfunction causes a bypass valve to fully open

• FLOW MISMATCH alarm (J-7-a) annunciates shortly after the bypass valve (BPV) opens Answer the following:

24 a) Is FLOW MISMATCH an expected alarm for the stated conditions?

b) What is the operational significance of this alarm at 40% power?

A. NO this is NOT expected. The significance is that a steam line break has occurred in the Turbine Building.

B. NO this is NOT expected. The significance is that extraction steam has isolated from feedwater heaters.

C. Yes this is expected. The significance is that extraction steam has isolated from feedwater heaters.

D. Yes this is expected. The significance is that Turbine Anticipatory Scrams have been bypassed.

ANSWER: D Note: This was closed reference question.

Question History No technical comments received prior to exam. Licensee made post-exam technical comments.

Licensee Comment:

Per UFSAR, section 10.2.1, the turbine bypass valve assembly consists of 9 bypass valves and will pass approximately 40% steam flow with all 9 valves open. This equates to each bypass valve passing less than 5% steam flow.

During the monthly surveillance of Turbine Bypass Valves (TBV), precaution 10.3.3 states that a load reduction of approximately 25 MWe will occur when each bypass valve is tested. This equates to approximately 4% power. The flow mismatch alarm is set for 7% steam flow, so one TBV fully open will not bring this alarm in. This was verified by one of the Shift Managers who stated that the flow mismatch alarm is never received when performing the TBV surveillance testing.

Based on the above information and the stem condition which states that only one bypass valve has failed open; the FLOW MISMATCH alarm would NOT be expected to come in and the only condition which would justify the mismatch alarm would be a steam line break in the Turbine Building.

Therefore the correct answer should be A (not D).

Oyster Creek recommendation: Accept A as the correct answer.

References:

RAP J-7-e, FLOW MISMATCH (sent previously)

OCNGS UFSAR, Section 10.2.1, Turbine Generator, page 10.2-1 (sent

25 previously) 625.4.002 Main Turbine Surveillances NRC Resolution:

The licensees original comment (April 27, 2004) requested that both A and D be accepted as correct answers. Subsequently, based on NRC staff feedback to the licensee, the licensee revised their recommendation to indicate that only A is a correct answer. The licensees original recommendation that D should also be considered a correct answer was based on a bypass relay failure, however, the NRC concluded that this was implausible for the following reasons:

1. Drawing 233R309, Turbine Control Diagram Revision 7 provides that the Bypass Relay operates all bypass valves through a common shaft. The 9 Bypass valves (BPV) are sequenced such than as the first valve approaches full open the second valve begins to open.

A failure in the Bypass Relay that fully opens one BPV will, through the common shaft, partially opens a second BPV.

2. Procedure 625.4.002, Main Turbine Surveillances, Revision 51, Section 10.0 completes the Bypass Valve Operability Test by stroking individual BPVs at Panel 13R.

3. When a single BPV is stroked, the panel indicating lights go from full closed (closed light LIT, open light off) to full open (open light LIT, closed light off)

4. If the Bypass Relay is the cause of failure there will be indication on the panel (position lights as well as servo meters) that will show one valve full open and a second valve partially (approximately 30%) open. The operator also has a selectable servo meter on the back panel that will, also, show more than one valve open.

5. Precaution 10.3.3 of Procedure 625.4.002 specifies that a load reduction of 25 MWE will occur when each bypass valve is tested. 25 MWE corresponds to approximately 4% power.

The procedure makes no mention of the FLOW MISMATCH alarm. Note: SROs questioned about this test indicated the FLOW MISMATCH alarm does NOT come in during the test.

6. The setpoint for the FLOW MISMATCH alarm (RAP J-7-a, Revision 121) is > 7% difference in the total steam flow and the sum of the steam flow through the turbine 1st stage and extraction steam flow to the 2nd stage reheater.

7. Finally, If bypass relay failure caused one bypass valve to be fully open then another BPV would be partially open. The operators would see this second valve in an intermediate position and would actually have more than one BPV open. This is contrary to the stem conditions and not applicable to the question. Therefore, a bypass relay failure is not a credible event that will result in failing a bypass valve to fully open.

The only credible failure is the BPV accumulator. In this instance only one valve will open and the FLOW MISMATCH will NOT be LIT. Since the operators periodically perform the Bypass Valve Operability Test and observe that during this test the FLOW MISMATCH alarm will NOT be LIT, it is reasonable for them to conclude that with only one BPV open the FLOW MISMATCH alarming would NOT be an expected condition. Since the setpoint for this alarm is

26 7% flow and the BPV passes only 4% flow it is reasonable for the operator to conclude that over 3% steam flow is going somewhere other than to the turbine and BPV. This would be an indication that there was a steam leak in the turbine building. In this instance, answer A would be correct.

Since answer D cannot be correct with only one BPV open, answer A is the only correct answer.

In conclusion, the NRC Staff accepts the licensees revised comment. Change the correct answer from D to A. Do not accept D as a correct answer.

Distractors B and C are wrong since extraction steam being isolated will not cause the stem conditions.

Distractor D is wrong since the stem conditions would not be expected with only one BPV open (i.e., one bypass valve with a capacity of approximately 4% would not cause a FLOW MISMATCH alarm).

27 Question: SRO 3 A loss of all drywell cooling has occurred and you have entered Primary Containment Control, EMG-3200.02 when the drywell temperature entry conditions are exceeded.

The following conditions exist:

• All attempts to restore drywell cooling have failed.

• Drywell pressure is at 2.75 psig and steady.

• When you direct the RO to vent the containment per support procedure 31" the STA notifies you that the drywell temperature is approaching 200 degrees F.

• NO other entry conditions for Primary Containment Control or RPV control exist at this point.

Answer the following:

Are you allowed to vent the containment? Also, provide a basis for this action.

A. Yes, reduction of drywell pressure is the most important strategy at this point.

B. Yes, venting the drywell will also result in reduction in drywell temperature.

C. No, venting the drywell will result in exceeding the Containment Spray Initiation Limit.

D. No, venting the drywell may cause a inadequate NPSH for the Containment Spray Pumps.

ANSWER: C Note: This was open reference question with EOPs provided as a reference to the applicants.

Question History Received comment 3/04 - D may also be right. Not required to vent, does not mean CSIL will be exceeded. Change required to vent to allowed to vent. Delete cannot bypass primary containment isolation signals (done). During validation week the drywell temperature was changed from 160 to 200. Licensee made post-exam technical comments.

Licensee Comment:

The question asks:

A loss of all drywell cooling has occurred and you have entered Primary Containment Control, EMG-3200.02 when the drywell temperature entry conditions are exceeded.

The following conditions exist:

• All attempts to restore drywell cooling have failed

• Drywell pressure is at 2.75 psig and steady

• When you direct the RO to vent the containment per support procedure 31 the STA

28 notifies you that the drywell temperature is approaching 200 degrees F

• NO other entry conditions for Primary Containment Control or RPV control exist at this point.

Answer the following: Are you allowed to vent the containment? Also, provide a basis for this action.

In the Containment Pressure leg of Primary Containment Control, if primary containment isolation is NOT required (i.e., pressure is less than 3 psig), direction is given to vent the containment in order to maintain containment pressure below 3 psig. Maintaining pressure below 3 psig assures no automatic initiations or isolations will occur.

Actions that automatically occur at 3 psig are:

• Reactor scram signal is generated on high drywell pressure

• Core Spray system start is generated on high drywell pressure

• EDG #1 and #2 start and idle on high drywell pressure

• RWCU system isolation on high drywell pressure

• Shutdown Cooling system isolation on high drywell pressure

• Primary Containment isolation on high drywell pressure (sumps, ventilation and purge isolation valves, TIPs and TIP purge, and RB to Torus vacuum breakers)

By maintaining drywell pressure below 3 psig, it simplifies mitigation strategy by not having to deal with the above initiations and isolations.

Answers C and D CANNOT be correct, as it states venting is NOT allowed. This would be in direct conflict with the directions to vent the containment and maintain pressure below 3 psig.

Answers A and B are both correct for the following reasons.

In answer A, directions to vent the containment per the steps in the Pressure Control leg do take precedence over any directions to spray in the Drywell Temperature leg. While it is true that we cannot spray the drywell if torus pressure and drywell temperature are not within the Containment Spray Initiation Limit (CSIL), there is absolutely NO direction implicit or explicit to secure the venting if it will result in dropping below the CSIL. By procedure, we are required to vent the containment to keep it less than 3 psig, to prevent the automatic initiations and isolations mentioned above.

In answer B, venting the containment will result in a reduction of temperature. This is a classic Ideal Gas Law concept. Since the containment volume is constant, any reduction in pressure will result in a corresponding reduction in temperature. This is expressed below.

P1V1/T1 = P2V2/T2 This concept is part of the Generic Fundamentals course the candidates went through Any reduction in drywell pressure will cause a corresponding reduction in drywell temperature.

While the basis for answer A is directly related to the EOPs, the basis for answer B is a

29 fundamental concept, which is reinforced during all phases of training. The question did NOT distinguish between a procedurally driven concept or a fundamental concept. Therefore, answers A and B are correct.

Oyster Creek recommendation: Accept A and B

References:

EMG-3200.02, Primary Containment Control (sent previously)

EOP Users Guide, pp. 2-28 and 2-29 (sent previously)

BWR Generic Fundamentals, Thermodynamics, Chapter 3, Steam (sent previously)

DOE Fundamentals Handbook, Thermodynamics, Heat Transfer, and Fluid Flow (sent previously)

NRC Resolution:

NRC Staff reviewed the technical documents provided including the EOPs and EOP Users Guide. The Primary Containment Control EOP procedure is entered upon drywell temperature exceeding 150 degrees F (stem condition). The pressure leg and drywell temperature legs are denoted with branching lines and are therefore intended to be performed concurrently. In this case, the operator will observe in the Pressure leg (again from stem conditions) that containment isolation is not required and will proceed to Vent the primary containment to maintain pressure below 3.0 psig...

In parallel, the operator will enter the Drywell Temperature leg and will Monitor bulk drywell temperature... In the Drywell Temperature leg the SRO will proceed through the first two steps which will attempt to Maintain bulk drywell temperature below 150 degrees F using available drywell coolers. This effort has not been effective so far since the drywell temperature is approaching 200 degrees F.

The question asks the applicant, Are you allowed to vent the containment? Also, provide a basis for this action. Choice A is a correct answer since it correctly answers Yes to the first part of the question. Secondly, it provides a basis for venting the Drywell and at this point it is the most important strategy. Venting is the procedurally required action to control pressure with the stated conditions in the stem. The EOP users guide states the basis for venting is to ...

assure that normal methods of Primary Containment pressure control are attempted in advance of initiating more complex actions to terminate increasing Primary Containment pressure (e.g.

initiating drywell sprays at 12 psig in the torus or drwyell). In addition, by maintaining drywell pressure <3.0 psig Isolations of Reactor Building Closed Cooling Water (RBCCW), Instrument Air, Reactor Water Cleanup (RWCU), Vent and Purge lines will be avoided also unnecessary starting of both emergency diesel generators and the Core Spray system. These support systems provide for a transition to normal procedures for subsequent cool down operations. In addition, by maintianing drywell pressure below 3 psig, it simplifies the mitigation strategy by not having to deal with these isolations and initiations. There are no stem conditions that indicate there is an RPV level control issue, so isolations from Lo-Lo or Lo-Lo-Lo RPV water level are not a concern at this time.

B correctly answers Yes to the first part of the question but it does not provide a correct

30 basis for venting the drywell. Although, venting the drywell will result in some very small reduction in drywell temperature initially, it is not a basis for this action. The EOP Users Guide makes no mention of venting being used as a mechanism for reducing drywell temperature.

Furthermore, there is no direction in the temperature control leg to vent (i.e., as a strategy to reduce temperature). The reduction in temperature (though a physical phenomena associated with the ideal gas laws) should NOT be considered as a basis for the action (to vent or not to vent). Although, it is recognized that venting may preclude the pressure from increasing (and therefore preclude further pressure-induced temperature increases) this was not what Answer B provided. Answer B provided that the basis for venting was that it will ...result in reduction in drywell temperature. Again, the small reduction in pressure will have no discernable effect on drywell temperature.

Furthermore, when questioned on the effect that venting would have on long-term temperature in the drywell, the licensee responded that they expected temperature to continue to increase.

The containment temperature will continue to increase due to the reactor plant system heat losses to the containment atmosphere. In addition, the containment volume is not purged during venting, therefore, the heat remains in containment. With a failure of drywell cooling (as stated in the question), the containment temperature will continue to increase with the conditions stated in the question. The containment temperature will not be reduced until RPV temperature is reduced below the existing drywell temperature by forcibly cooling the plant down, which is beyond the scope of this question. Since drywell temperature is expected to continue increasing with the stated conditions in the question, it cannot be legitimately argued that venting will also result in a reduction in drywell temperature. Answer B should NOT be considered correct. The correct EOP basis for venting is to assure that normal methods of Primary Containment pressure control are attempted in advance of initiating more complex actions to terminate increasing Primary Containment pressure.

In conclusion, the NRC Staff does not accept the licensees comment to accept both A and B as correct answers, A is the only correct answer to this question.

B is wrong since there is no action specified in the temperature control leg to vent and no mention of venting as a strategy to control drywell temperature in the EOP Users Guide. In addition, Drywell temperature is expected to continue to increase even while venting is being performed.

C is wrong since venting is directed by the EOPs under these conditions.

D is wrong since venting is directed by the EOPs also no stem conditions indicate elevated torus temperature (and therefore no impact on NPSH).

31 Question: SRO 7 It is a particularly cold January night. The Turbine Building Operator calls you up to let you know that the 4160 V switchgear room temperature is abnormally cool with a local room thermometer reading only about 40 degrees F.

What immediate action(s) are required?

A. Initiate a Temporary Configuration Change Package (TCCP) and install a portable heater in the room.

B. Initiate an Action Request to have install a portable heater in the room.

C. Conservatively, declare the 4160 Switchgear Room Fire Suppression System inoperable and assign a continuous Fire Watch in the room.

D. Determine the reactor must be placed in the COLD SHUTDOWN CONDITION while attempting to resolve any HVAC problems.

ANSWER: D Note: This was a closed reference question.

Question History On 1/6/04 comment-You will declare C battery inoperable. You will shutdown in 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

3/04 Change all answers to final form(specified by OC). Licensee made post-exam technical comments.

Licensee Comment:

The question asks:

It is a particularly cold January night. The Turbine Building Operator calls you to let you know that the 4160 V switchgear room temperature is abnormally cool with a local room thermometer reading only about 40 degrees F.

What immediate action(s) are required?

The suggested answer D is NOT correct. The stated explanation assumed this condition would result in the C Battery being declared inoperable, forcing a Tech Spec shutdown to cold shutdown conditions. The C battery is housed within a separate room inside the A/B 4160 V switchgear room. The C Battery room has its own separate ventilation system with thermostatically controlled heaters. Therefore, the stated question conditions do not affect the C Battery.

The question as presented is still a valid question. Turbine Building HVAC operating procedures require us to maintain temperature above 50 degrees F in the 4160 V switchgear room. In the

32 event it drops below 50 degrees, compensatory actions must be taken. These compensatory actions would entail installing portable heating as required, to assure temperatures are maintained above 50 degrees.

The actions to install portable heaters are driven by the Work Control Process and the Temporary Configuration Control Process.

Within the TCCP Procedure (CC-AA-112, Rev. 7) step 4.1.8, covers Installation of the TCCP. In the situation given in the question, installing temporary heating will involve Operations as well as Maintenance Department personnel. Installing the TCCP (temporary heater installation) requires the initiation of an Action Request (AR) in order to track the work to completion. The AR is required per WC -AA-101-1001, Work Screening and Processing.

Answer A is a correct statement, in that initiation of a TCCP and installing a portable heater in the room will mitigate the problem. Answer B is a correct statement, in that initiation of an Action Request is the first step to have a portable heater installed in the room.

Therefore, answers A and B are correct statements, and would both lead to portable heating being installed in the room.

Oyster Creek recommendation: Accept A and B

References:

Procedure 340.3, 125 Volt DC Distribution System C, pp. 2.0 and 16.0 (sent previously)

Procedure 328, Turbine Building HVAC(revision 43), Sect 5.2 CC-AA-112, Temporary Configuration Changes (revision 7) pp. 1,5-11 WC -AA-101-1001, Work Screening and Processing (revision 2), pp. 5, 7 NRC Resolution:

The lesson plan DC Distribution 2611-PGD-2621, Revision 07, page 4 of 19 specifies that the location of the C battery is Turbine Building mezzanine level in the 4160 V switchgear room.

The licensee provided additional information that pointed out the C battery room and 4160 V switchgear rooms have separate ventilation, and although the C battery room is contained within the 4160 V switchgear room (and subject to the same environmental conditions) it has its own thermostatically controlled heater in the HVAC duct. It cannot be assumed that the battery room will be at the same temperature as the switchgear room. This was confirmed from a review of a floor plan drawing and temperature logs from last winter. Therefore, the 4160V swictchgear room temperature can not be assumed to have any impact on the C battery or battery room. The original assumptions (i.e., regarding 4160 V switchgear room configurations and battery locations) used in developing this question were incorrect, therefore, D is an incorrect answer.

Procedure 328, Turbine Building Heating and Ventilation, Revision 43 step 3.2.4 specifies that the Turbine Building Heating and Ventilation System should be operated to maintain a minimum temperature of 50 degrees F in all areas of the Turbine Building. Step 5.2.5 specifies Maintain a minimum temperature of 50 degrees F in the Turbine Building as indicated by three indicators-SOUTH AIR TEMP, ROOF TEMP, NORTH AIR TEMP... Although the local room temperature is not included in this list, this temperature is checked by the in-plant operator

33 when performing daily rounds. It is also reasonable to expect that the SRO would direct action to be taken to restore the 4160 V Bus Room > 50 degrees F. Since they are already operating the system per Procedure 328 and (given the stem conditions) would conclude the HVAC was being taxed by the particularly cold January night. The SRO would be expected to respond to the abnormally cold temperature in the room and will direct that action be taken to install an additional heat source in the room.

The questions asks, What immediate action(s) are required? The following actions are required in order to successfully install a portable heater in the 4160 V switchgear room.

1) Procedure CC-AA-112 Temporary Configuration Changes, Attachment 2 specifies that Air movers that are used to replace/augment a design function of a permanent HVAC system require a Temporary Configuration Change Package (TCCP)... Since the installation of a portable heater in the battery room would involve a temporary change to a permanent HVAC system, the use of a TCCP is required in order to install the heater (Answer choice A).

2) Work Screening and Processing, WC-AA-101-1001, Revision 2, section 2.20 indicates that modifications per procedure CC-AA-112 is specifically listed as a work category included in the WR(AR)s in the work management process in order to track the work to completion. Installing a portable heater in the room will involve both operations and maintenance personnel and will require the initiation of an Action Request (AR) in order to track the completion of work (Answer choice B).

Both answers A and B are partially correct but incomplete answers. Since both actions (i.e.,

TCCP and AR) are required for installation of the portable heater in the 4160 V switchgear room, the heater can not be installed without completing both actions. Accordingly, there is not correct answer to the question.

In conclusion, the NRC Staff does not accept the licensees comment. The question is deleted.

A and B are partially correct but incomplete answers, since installation of the portable heater in the 4160 V switchgear room require both the initiation of a TCCP and an AR, the heater can not be installed without completing both A and B actions.

C is wrong since there is no indication that freezing of Fire Protection will occur.

D is wrong since the battery room is separate from the 4160 V room and has its own heating source. The temperature of the 4160 V Bus room is unrelated to the battery room or battery temperature.

34 Question: SRO 12

-At noon on April 1, 2004 the plant is at 80% power with three reactor recirc pumps operating (NG01-A, C and E). NO LCOs are in effect at this time. At 12:05 PM the following conditions occur on the AC distribution system:

• The following alarms annunciate:

• MN BRKR 1B TRIP

• MN BRKR 1B 86 LKOUT TRIP

• BUS 1B UV

• S1B BRKR TRIP

• S1B BRKR OL TRIP/BRKR PERM OPN

• 4160V BUS 1B voltmeter is reading downscale

• 4160V BUS 1A voltmeter is reading 4160 volts

• EDG No. 2 has started and has energized 4160V Bus 1D

• Security reports that Startup Transformer SB deluge system is discharging on the transformer.

• All other switchyard equipment is available for use.

The operators quickly respond to the 1B Bus alarms and indications (using OPS-3024.10a) and stabilize the plant within the design capability of the remaining energized systems and components. All applicable Technical Specification ACTION statements are satisfied.

Answer the following:

1. What is the maximum power level sustainable with the AC distribution configuration as it exists at 12:05 PM?

2. How long can the conditions existing at 12:05 PM be allowed to continue?

A. The plant would have scrammed from the transient. The existing conditions can be maintained indefinitely.

B. The plant could be run at approximately 33% power. The existing conditions can be maintained for 7 days.

C. The plant could be run at approximately 50% power. The existing conditions can be maintained for 7 days.

D. The plant could be run at approximately 33% power. The reactor must be placed in the COLD SHUTDOWN CONDITION.

ANSWER: B This was a closed reference question.

Question History

35 3/04 The power level of 80% in the stem was chosen based on a TS limitation of 90%. The licensee had recommended changing this to 50% based on a change to Procedure 202.1 but this was not incorporated due to time constraints. In any case, this still would not have resulted in an acceptable question, since ABN-17, Feedwater System Abnormal Conditions, Rev 0 was subsequently issued and the information in this ABN revision was not incorporated into the exam.

Licensee Comment:

The stated initial plant conditions cannot be met at Oyster Creek. ABN-2, Recirculation System Failures (revision 0), which gives operator direction to respond to a tripped recirc pump which results in three recirc pumps operating after the trip and Procedure 202.1, Power Operation (revision 77), which contains direction to secure one of the recirc pumps with only four pumps initially operating cover this condition. In each case, the operator is directed to get final recirc pump speed below 33 Hz, to ensure no NPSH issues with the operating pumps. The final pump speed of <33 Hz will result in total core flow of approximately 7.5 E4 GPM (which equals ~ 65%

power).

In the previous revision of ABN-2, if a recirc pump trip resulted in three loop operation, the operator was directed to immediately reduce recirc pump speed to less than 33 Hz. If this was done from initial power levels of 100%, a power to flow scram would have occurred when recirc flow dropped below 7.68 E4 GPM. At 7.68 E4 GPM, the flow biased scram setpoint takes a prompt drop from approximately 88% to approximately 65%. Because of this possibility, the procedures were changed to accomplish the recirc flow reduction in three distinct steps. The first step is to reduce recirc flow to 8.5 E4 GPM (top of the buffer zone.) Once that is accomplished, reactor power is reduced to less than 55% by insertion of CRAM rods. Once power is below 55%, flow can then be reduced further to meet the requirement of pump speed less than 33 Hz.

The stem of the question indicates a loss of Bus 1B. This bus loss will result in the loss of B and C Reactor Feed Pumps, as well as B and C Condensate Pumps.

Considering the question with the given plant conditions, the stated transient will result in a reactor scram, either due to a loss of sufficient feedwater flow causing an automatic scram on reactor low water level, or a manual scram due to expected operator actions of ABN-17, Feedwater System Abnormal Conditions. These expected operator actions require a manual scram if a multiple feed or condensate pump trip occurs.

While the first part of suggested answer A is a correct statement (saying the plant would have scrammed from the transient), the second part of the statement is NOT true. The plant must be cooled down to a cold shutdown condition if the loss of the startup transformer lasts for longer than 7 days by Tech Spec section 3.7 dealing with AC power sources.

Answers B, C, and D are not correct because the plant will have scrammed.

Therefore, there is no correct answer for this question, and the question should be deleted.

Oyster Creek recommendation: Delete this question.

36

References:

ABN-17, Feedwater System Abnormal Conditions, section 3.3 pg. 12 (sent previously)

Technical Specifications, section 3.7 (sent previously)

ABN-2, Recirculation System Failures Procedure 202.1, Power Operation NRC Resolution:

The region agrees with the licensee that power could not be at 80% as indicated in the stem conditions with only three recirc pumps operating. ABN-2, section 3.1.2.E would limit pump speed to a maximum of 33 HZ, therefore, power would eventually be limited to 55% power with these plant conditions. Considering the question with the given plant conditions, the transient will result in a reactor scram due to a loss of feed water flow causing an automatic scram on reactor low water level, or a manual scram due to expected operator actions in ABN-17, Feedwater System Abnormal Conditions. ABN-17, Step 3.3.C requires SCRAM the reactor and execute ABN-1" for multiple feed pump trips.

Since the loss of the Startup Transformer results in the loss of two reactor feed pumps (B and C), answers B, C and D cannot be correct. That is, the plant could not be run at any power level specified in any of these answers. TS 3.7.B.1 specifies that The reactor may remain in operation for a period not to exceed 7 days if a startup transformer is out of service. The question stem provided no indication that the startup transformer would be returned to service in less than 7 days. Since the TS precludes the plant from maintaining the existing conditions indefinitely answer A is also incorrect. Therefore, there is no correct answer provided for the question.

As noted above, all distractors have some flaw that makes them technically incorrect.

In conclusion, the NRC Staff does accept the licensees comment. The question should be deleted.

37 Question: SRO 22 One hour has elapsed since a steam line break occurred in the Turbine Building. The transient has caused fuel damage, a reactor scram, but manual closure of the MSIVs was NOT successful. Following the transient the following conditions exist:

• All rods reached 00 on the SCRAM

• Torus temperature is 96 degrees F

• There is indication of 50,000 lbs/hr flow on the A main steam line flow instrument

• RPV level is 60" TAF and slowly increasing from a low point of 30" TAF

• RPV pressure is 760 psig and dropping slowly

• Security calls and informs you that steam can be seen issuing from, the Turbine Building

• Chemistry sampling results of reactor coolant are NOT in yet but the accompanying HP reported that the sample bottle was 5 R/HR when the chemist left the sample station

• Iodine release is 50 uCI/sec

• An HP calls from Route 9 bridge and reports 700 mREM/hr TEDE at his location Classify the event.

A. General Emergency B. Site Area Emergency C. Alert D. Unusual Event ANSWER: A Note: This was open reference question with EPIP-OC-.01, Appendix 1 provided as a reference to the applicants.

Question History This was a modified bank question. Comment received 3/04 Would meet GE (2 of 3 barriers lost and potential to lose third) change answer to A (done). Licensee made post-exam technical comments.

Licensee Comment:

Per EPIP-OC-.01, Classification of Emergency Events (revision 14), Category J, Radiological Releases,:

• Iodine release greater than 40 mCi/sec is an ALERT classification [J-2].

• Valid integrated dose at or beyond the site boundary of $ 5 mREM but # 1000 MREM TEDE is a SITE AREA EMEGENCY [J-4].

Based on the HP call of 700 mREM[/hr] TEDE at the Route 9 bridge, this constitutes a SITE AREA EMEGENCY, not a GENERAL EMERGENCY.

38 Therefore the correct answer should be B (not A).

Oyster Creek recommendation: Accept B as the correct answer.

References:

EPIP-OC-.01, Classification of Emergency Events (revision 14), Category J.

(sent previously)

NRC Resolution:

The NRC staff conducted a review of EPIC-OC-.01, Oyster Creek Emergency Preparedness Implementing Procedure, Revision 14. The following is a summary of the findings:

1.Categories A-G relate to RPV Level, RPV Pressure, RX Power, Drywell Temperature, Containment Pressure, Torus Temperature and Torus level; respectively. The highest level of EAL for any of these parameters is ALERT (based on RPV level < 61").

2.Category H pertains to RCS integrity. This category yields an Alert since MSIVs have not isolated.

3. Category I pertains to Fuel Conditions. This category has no direct EAL based on stem conditions, however with a reactor coolant sample reading 5 R/HR this could reach UE (if the sample reads > 0.2 uCI/gm of iodine).

4. Category J pertains to Radiological Releases. This category has an EAL of Site Area Emergency based on 700 mREM TEDE beyond the site boundary.

5. Categories K through R have no applicable conditions reflected in the stem.

6. Category S pertains to Fission Product Barriers. This category would dictate a Site Area Emergency Classification based on the following: 1) The basis for Category S states, Regardless of plant condition, consideration should be given in declaring a General Emergency for a loss of cladding which has Rad level increases as specified in EAL category J (Radiological Releases). 2) Category J criteria for a Site Area Emergency states, A valid integrated dose at or beyound the Site Boundary of greater than or equal to 50 mRem but less than 1000 mRem total whole body dose (TEDE)... The question stem indicates 700 mRem TEDE, therefore, based on category J criteria this should be classified as a Site Area Emergency. 3) The basis for category S states, Exhibit 2 provides guidelines for assessing fission product barriers status. None of the conditions provided in the question stem exceed the established criteria for making the determination that the Fuel Clad experienced either a Potential Loss (i.e., Main Steamline Radiation monitor High-High; RPV level less than or equal to -30" TAF; Rx Power Ocillations) or a Barrier Loss (i.e., Coolant activity exceeds 300 uci/gm dose equivalent iodine; Off-gas discharge indicates greater than 10,000 mRem/Hr). Based on an assessment of the Fission Product Barrier Guidelines only 2 of 3 Fission Product Barriers are lost, therefore, the stem conditions do not satisfy the EAL for General Emergency (i.e.,

potential loss of the third barrier).

7. For Category T (Emergency Directors judgement) there is no EAL above Site Area Emergency, so even a conservative assessment of the failures noted in the stem would not exceed SAE.

39 Note: Even though there was a typo in the stem condition of 700 mREM/hr TEDE (should have been 700 mREM TEDE) the stem still provided adequate information to yield a proper response.

Since the release rate was one hour, 700mREM/hr would yield 700 mREM TEDE.

Therefore, it was concluded that the correct classification for the stated stem conditions is Site Area Emergency. This is answer B.

In conclusion, the NRC Staff accepts the licensees comment. The correct answer should be changed from A to B.

A is wrong since the EPIC, Category J *indicates Site Area Emergency. In addition, based on an assessment of category S and the Fission Product Barrier Guidelines only 2 of 3 Fission Product Barriers are lost, therefore, the stem conditions do not satisfy the EAL for General Emergency (i.e., potential loss of the third barrier).

C and D are wrong since EPIC classifies as Site Area Emergency.

40 Question: SRO 23 The plant is in normal full power operation with no LCOs on April 1, 2004 when massive grid instabilities result in the loss of offsite power for the foreseeable future. The plant responds as designed including both Standby Diesel Generators which have started and loaded to their respective buses. The following conditions exist as of noon on April 1, 2004:

• Diesel fuel oil delivery is uncertain due to infrastructure problems

• The Standby Diesel Generator Fuel Tank is at 14,500 gallons

• The heating boiler tank has 16,500 gallons of available fuel

• NO other sources of diesel fuel are available on site

• The heating boilers are shutdown for maintenance How long is the fuel supply adequate considering the TS Basis consumption rate?

For your answer assume two diesels continue to run at the consumption rate specified in Amendment 18. Round off you answer to the nearest day.

A. Three days B. Four days C. Five days D. Seven days ANSWER: B Note: This was a closed reference question.

Question History This was a modified bank question. Comment received 3/04 to change question from The System Dispatcher has asked how long you can continue in this mode and still be able to re-start the plant once power is restored to final form (as submitted by OC). Answer should be D (not incorporated). Licensee made post-exam technical comments.

Licensee Comment:

Based on the given information, there is 31,000 gallons of diesel fuel available for emergency diesel engine operation. Technical Specifications bases for section 3.7, Auxiliary Electrical Power, assumes the Emergency Diesels are available to be run as long as the fuel supply holds out. The fuel supply takes into consideration the Diesel Fuel Oil tank, as well as the heating boilers fuel supply. Therefore, taking into consideration 14,500 gallons in the fuel oil tank and 16,500 in the heating boiler tank, there is a total of 31,000 gallons, NOT just 16,500 as stated in the question explanation.

The 3-day consumption rate specified in Oyster Creek Technical Specification Amendment 18 is 12,410 gallons of fuel, which equates to 4,136.66 gallons per day. By dividing 31,000 gallons

41 by 4136.66 gal/day, the maximum run time is 7.49 days of operation.

The question asks: How long is the fuel supply adequate considering the TS Basis consumption rate?

Since the question does NOT ask for the longest or maximum time the diesels will run with the available fuel supply, ALL four answers can be considered correct (3, 4, 5 and 7 days). Under all cases, the supply of fuel oil is adequate to cover all four answers.

Therefore, this question should be deleted.

Oyster Creek recommendation: Delete this question

References:

Technical Specifications, Section 3.7, Auxiliary Electrical Power, and bases.

(sent previously)

NRC Resolution:

The question asks How long will the fuel supply be adequate considering the TS Bases consumption rate. It goes on to say Round off your answer to the nearest day. Under these unusual conditions the operators would be expected to run the diesels until the fuel actually ran out. This consists of a total amount 31, 000 gallons of fuel (i.e., 14,500 gallons in the fuel oil tank and 16,500 in the heating boiler tank. The calculated time (using TS consumption rate) that the fuel supply is adequate to run the diesels is 7days (rounded to the nearest day). That is, 7 days is the answer to How long is the fuel supply adequate considering the TS Basis consumption rate. The correct answer is D.

The licensee contends that the question is not looking for the longest time the diesels will run with the available fuel. The question was always intended to ask for the longest when it asked How long is the fuel supply adequate. The original question context was related to TS limitations (i.e., the original intent of this question got modified prior to administration based on feedback from licensee), however, the emphasis on length of the limitation still applied to question on the exam, since 7 days is the properly calculated limitation and 7 days is longer than three, four or five days. Therefore, A, B, and C are incorrect answers since they are all shorter than 7 days and D is the only correct answer.

However, upon further review the NRC staff has concluded this question should be deleted from the exam since Oyster Creek does not have a learning objective that requires SROs to recall from memory the diesel consumption rate per TS Amendment 18 and 32. This information was not provided as a reference during the exam, therefore, the question is considered inappropriately difficult (level of difficulty = five) and should be deleted.

In conclusion, the NRC Staff accepts the licensees recommendation to delete the question but for a different reason than was suggested by the licensee.

Question: SRO 25

42 A drywell entry must be made in order to inspect for increased unidentified leakage. A plant shutdown is in progress. The following conditions exist:

• Reactor Power is 90% and decreasing

• Purging of the drywell with air is in progress in accordance with Procedure 312.9, Primary Containment Control.

• The Chemistry Department indicated that the Stack Gas Activity should NOT exceed 900 CPS, based on their sample

• DRYWELL VENT-PURGE INTERLOCK BYPASS switch is in the BYPASS position (Panel 12XR)

• Venting is via the Reactor Building Ventilation System

• Stack gas activity is at 1100 CPS and slowly increasing Your direction to the operator(s) controlling the purge in accordance with Procedure 312.9 is that they are required to:

A. Decrease the purge flow until stack gas activity decreases below 900 CPM B. Confirm stack release rate with RAGEMS and then decrease purge flow rate.

C. Secure the primary containment purge by closing V-28-17 and V-28-18.

D. Shift the purge to go through the Standby Gas Treatment System ANSWER: C Note: This was open reference question with Section 7.1 and 7.2 of Procedure 312.9 provided as a reference to the applicants.

Question History No technical comments received from OC prior to exam. Licensee made post-exam technical comments.

Licensee Comment:

43 The question asks:

A drywell entry must be made in order to inspect for increased unidentified leakage. A plant shutdown is in progress. The following conditions exist:

• Reactor power is 90% and decreasing

• Purging of the drywell with air is in progress in accordance with Procedure 312.9 Primary Containment Control

• The chemistry department indicated that Stack Gas Activity should not exceed 900 cps, based on their sample

• Drywell vent-purge interlock bypass switch is in the bypass position

• Venting is via the Reactor Building Ventilation System

• Stack gas activity is at 1100 cps and slowly increasing Your direction to the operator(s) controlling the purge in accordance with Procedure 312.9 is that they are required to: ( Reference material was supplied during exam)

Step 7.2.4 of procedure 312.9 (precautions and limitations) says . . . If the primary Containment requires venting and the potential exists for airborne activity to be higher than normal, consideration should be given to vent through the Standby Gas Treatment System.

Therefore the correct answer would be D based on the provided references.

Step 7.3.2.6 of 312.9 (steps to depressurize the Torus) says IF stack gas activity exceeds 1000 cps, THEN immediately SECURE the purge.

a. CLOSE Torus Vent V-28-17

b. CLOSE Torus Vent V-28-18

c. NOTIFY the OS The suggested answer to the question was C, to secure the primary containment purge by closing V-28-17 and V-28-18. However, this information was not available in the provided references. It is not expected for the candidates to memorize a discrete action setpoint contained within an operating procedure, especially if it is a setpoint that is not readily recognized. Candidates were not supplied section 7.3 of procedure 312.9.

The candidates were only provided sections 7.1 and 7.2 of procedure 312.9, hence they all chose the answer dealing with the above-stated precaution to vent through Standby Gas Treatment System. The answer the students chose was based upon the supplied sections of the procedure.

Therefore, answer D is correct based upon the provided references.

Oyster Creek recommendation: Accept D as the correct answer.

44

References:

Procedure 312.9, Primary Containment (sent previously)

NRC Resolution:

Procedure 312.9, Primary Containment Control, Revision 30 is the System Operating Procedure. Prior to exam administration, during the exam review phase and based on discussions between the exam developer and the licensee, it was agreed that references should be provided for the applicants to use in answering this question. It was agreed that sections 7.1 and 7.2 of Procedure 312.9 should be adequate, considering the training given on the System Operating Procedure. However, the correct answer to the question was actually contained in step 7.3.2.6, which was not included in the reference provided to the applicants.

This step specifies to Close Torus vent valves V-28-17 and V-28-18". Upon reviewing the results of the exam, it was clear that the applicants used the provided reference material for the question and determined that answer D was supported by step 7.2.4. Step 7.2.4 specifies

...potential exists for airborne activity to be higher than normal, consideration should be given to vent through the Standby Gas Treatment System.

Although, we understand the applicants dilemma, we find that answer D cannot be technically supported as correct. Specifically, the operator would not continue venting through SGTS after the stack activity exceeded 1000 CPS (1100 cps), since step 7.3.2.6. requires that, If stack gas activity exceeds 1000 cps, then immediately SECURE the purge: a. CLOSE Torus Vent V 17, b. CLOSE Torus Vent V-28-18..". It is important to note that by closing these two valves (V-28-17 and V-28-18), the purge path through the Standby Gas Treatment System would be secured. Therefore, these two possible answer choices (C and D) are mutually exclusive procedure steps (i.e., If stack gas activity exceeds 1000 cps then by procedure the Standby Gas Treatment System would be secured). Therefore, for the given conditions in the stem, Stack gas activity is at 1100 CPS and slowly increasing, there is only one technically correct answer C (step 7.3.2.6 of the procedure). The SRO candidates would not be expected to know step 7.3.2.6 from memory and this section of the procedure was not provided as part of the reference. In summary, this question is deleted from the SRO exam, since the question is flawed (i.e., too difficult - level of difficulty LOD=5) and since answer D is incorrect.

In conclusion, the NRC Staff does accept the licensees comment and will delete this question.

Distractors A and B are wrong since they are not procedurally driven Distractor C is wrong since this step is contained in material not available to the applicant, is in conflict with information that was made available to the applicant, and is a discrete piece of knowledge not expected to be memorized by the SRO applicants (LOD=5).

Distractor D is wrong since it is in conflict with step 7.3.2.6.

SUMMARY

45 Question Original Correct Licensees NRC Resolution Number Answer Recommendation RO-19 C C & D correct C is correct RO-23 C B & C correct C is correct RO-25 B B & C correct B & C correct RO-37 C C & D correct C is correct RO-47 B B & D correct B & D correct RO-71 D A A SRO-3 C A & B correct A is correct SRO-7 D A & B correct Delete question SRO-12 B Delete Question Delete question SRO-22 A B B SRO-23 B Delete Question Delete question SRO-25 C D Delete question Question # References used in Resolution

46 RO-19 EMG-3200.02, Primary Containment Control, Rev 4 EMRG-3200.01A, RPV Control-No ATWS, Revision 4.

2000-BAS-3200.02, EOP Users Guide, Rev 4. The Primary Containment Control procedure (EOP Procedure 312.9, Primary Containment Control, Revision 29 Support Procedure 27, Maximizing Drywell Cooling, Revision 16 RO-23 ABN-26, High Main Steam Line orOff Gas Activity, Revision 0.

Secondary Containment and SGTS Lesson Plan (2611PGD-2601) Revision 08 Procedure 330, Standby Gas Treatment System, Revision 40 Procedure 202.1, Power Operation, Revision 78 SYSTEM 1(2) FLOW PERMISSIVE alarm response(RAP B-2-e/B-2-f, Revision 130)

RO-25 EOP EMG-3200.01A, RPV Control- No ATWS, Revision 4 Support Procedure 9, Lineup for Core Spray System Injection, Revision 11 BSTR PUMP A/C (B/D) OL alarm response (RAP B-3-e/B-3-f, Revision 130 RO-37May 13, 2004 VM-RW-1316, RWM DETAILED DESIGN MANUAL, sections 3.5.2.3, 3.11.1, and 3.11.3.3 ABN-6, Control Rod Drive System RAP H-6-a, ROD DRIFT HU-AA-104-101, Procedure Use and Adherence, Revision 0,

47 RO-47 RAP 9XF-5-c, CIP-3 INV AC INP LOST, Revision 81 GPUN Memo 2252-96-001, dated January 11, 1996 Lesson Plan (Nuclear Instrumentation, Revision 03).

RO-71 Drawing 233R309, Turbine Control Diagram Revision 7 Procedure 625.4.002, Main Turbine Surveillances, Revision 51 OCNGS UFSAR, Section 10.2.1, Turbine Generator, pg. 10.2-1 Procedure 625.4.002, Main Turbine Surveillances, Revision 51 FLOW MISMATCH alarm (RAP J-7-a, Revision 121)

SRO-3 EMG-3200.02, Primary Containment Control, Revision 4 EOP Users Guide, pp. 2-28 and 2-29, Revision 4 BWR Generic Fundamentals, Thermodynamics, Revision 3, Chapter 3, Steam DOE Fundamentals Handbook, Thermodynamics, Heat Transfer, and Fluid Flow June 1992

48 SRO-7 Procedure 340.3, 125 Volt DC Distribution System C, Revision 26 pp.

2.0 and 16.0 CC-MA-103-1001, Implementation of Configuration Changes, Revision 4, pp.

1-8 Lesson Plan DC Distribution 2611-PGD-2621, Revision 07 Procedure 328, Turbine Building Heating and Ventilation, Revision 43 Procedure CC-AA-112 Temporary Configuration Changes, Revision 6 SRO-12 ABN-17, Feedwater System Abnormal Conditions, Revision 0, section 3.3 pg. 12 Technical Specifications, section 3.7 SRO-23 EPIC-OC-.01, Oyster Creek Emergency Preparedness Implementing Procedure, Revision 14.

SRO-25 Procedure 312.9, Primary Containment Control, Revision 30