ENGINEERING FEASIBILITY AND COSTS OF CONVERSION 

OF INDIAN POINT UNITS 2 AND 3 TO A CLOSED-LOOP CONDENSER 

COOLING WATER CONFIGURATION 

Prepared for Entergy Nuclear Indian Point 2, LLC, and Entergy Nuclear 

Indian Point 3, LLC 

Prepared by: 

Enercon Services, Inc. 

500 TownPark Lane, Suite 275 

Kennesaw, GA 30144 

February 12, 2010 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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TABLE OF CONTENTS

Attachments ............................................................................................................................... iii

Executive Summary ................................................................................................................... iv

1 Background and Introductions ................................................................................................ 1

1.1 History .............................................................................................................................. 1

1.2 Purpose and Scope of this Report .................................................................................... 6

2 Conceptual Design .................................................................................................................. 7

2.1 Conversion of Unit 2 and Unit 3 ...................................................................................... 7

2.2 Conversion of Only Unit 2 ............................................................................................. 14

2.3 Conversion of Only Unit 3 ............................................................................................. 14

3 Station Operational Parameters ............................................................................................. 15

3.1 Administrative/Operating Limits ................................................................................... 15

3.2 Closed-Loop Operational Efficiency (PEPSE Analysis) ............................................... 16

4 Algonquin Pipeline Relocation ............................................................................................. 21

4.1 Pipeline Configuration ................................................................................................... 21

4.2 Feasibility of Relocation ................................................................................................ 22

4.3 Spectra Schedule and Cost Impacts ............................................................................... 23

5 Blasting ................................................................................................................................. 25

5.1 Restrictions to Blasting at IPEC ..................................................................................... 25

5.2 Cost and Schedule Impacts ............................................................................................ 27

5.3 Blasting Outage Timing ................................................................................................. 28

6 Spoils Removal ..................................................................................................................... 29

6.1 Blasting Spoils................................................................................................................ 29

6.2 Contamination of Spoils ................................................................................................. 30

6.3 On-Site Relocation of Spoils .......................................................................................... 30

6.4 Off-Site Relocation of Spoils ......................................................................................... 30

6.5 Cost and Schedule Impacts ............................................................................................ 32

7 Cooling Tower Operation / Plume Emissions ...................................................................... 33

7.1 Water Consumption........................................................................................................ 33

7.2 Cooling Tower Plume Emissions ................................................................................... 38

7.3 Plume Abatement ........................................................................................................... 38

8 General Site Considerations .................................................................................................. 40

8.1 Aesthetic Impacts ........................................................................................................... 40

8.2 Archaeological Considerations ...................................................................................... 40

8.3 Local Zoning Restrictions .............................................................................................. 41

8.4 Sound Restrictions .......................................................................................................... 43

9 Construction and Outage Duration ....................................................................................... 45

9.1 Conversion of Unit 2 and Unit 3 .................................................................................... 46

9.2 Conversion of Only Unit 2 ............................................................................................. 47

9.3 Conversion of Only Unit 3 ............................................................................................. 48

10 Economic and Power Loss Estimates ................................................................................... 49

10.1 Initial Capital Costs .................................................................................................... 49

10.2 Lost Electrical Generation Due to Construction Outage ............................................ 51
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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10.3 Lost Electrical Generation Due to New Condenser Operating Parameters and 

Parasitic Losses ......................................................................................................................... 51

10.4 Operations and Maintenance Costs ............................................................................ 52

11 Conclusions ........................................................................................................................... 54

11.1 Challenges to the NYSDEC Proposed Project ........................................................... 54

11.2 Duration of the NYSDEC Proposed Project............................................................... 55

11.3 Cost and Power Loss of the NYSDEC Proposed Project ........................................... 56

12 References ............................................................................................................................. 57
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

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Attachments 

Attachment 1 – 2003 Economic and Environmental Impacts Associated with 

Conversion of Indian Point Units 2 and 3 to a Closed-Loop Condenser 

Cooling Water Configuration 

Attachment 2 – Post Modification Site Rendering and Conceptual Drawings 

Attachment 3 – Subsurface Radiological Considerations Related to Construction of 

Closed-Loop Cooling at Indian Point Energy Center Units 2 and 3 

(GZA GeoEnvironmental, Inc.) 

Attachment 4 – Closed-Loop Performance 

Attachment 5 – Electrical Distribution Model Output Results 

Attachment 6 – Feasibility Evaluation of Relocating the Algonquin Gas Transmission 

Pipelines (Spectra Energy Transmission, LLC) 

Attachment 7 – Blasting Feasibility Study for Conversion of Indian Point Units 2 and 

3 to a Closed-Loop Cooling Water Configuration (Precision Blasting 

Services) 

Attachment 8 – Cultural / Historic Considerations for Cooling Tower Feasibility 

Attachment 9 – Construction Schedule 

Attachment 10 – Capital Cost Evaluation 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

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Executive Summary

Entergy Nuclear Indian Point 2, LLC, and Entergy Nuclear Indian Point 3, LLC (collectively, 

Entergy), have submitted a timely and complete renewal application for a State Pollutant 

Discharge Elimination System (SPDES) permit (SPDES Permit NY0004472) for Indian Point 

Energy Center (IPEC) nuclear powered electric generating stations 2 and 3 (collectively, the 

Stations, individually Unit 2 and Unit 3). The New York State Department of Environmental 

Conservation (NYSDEC) staff has proposed modifications in IPEC’s draft SPDES permit, 

including possible construction and operation of cooling towers in a closed-loop cooling 

configuration (NYSDEC Proposed Project). Consideration of the NYSDEC Proposed Project is 

subject to certain feasibility and alternative technologies assessments, as directed by the 

NYSDEC Assistant Commissioner’s August 13, 2008 Interim Decision. Accordingly, NYSDEC 

may revisit its proposed modifications to the draft SPDES permit for IPEC and change them 

pursuant to Entergy’s closed-loop cooling feasibility and alternative technologies reports. 

The Interim Decision provides that Entergy must submit an engineering report that addresses 

significant construction and operational considerations, associated with conversion of the 

Stations’ existing cooling water systems to closed-loop cooling, taking into account site 

constraints, including, but not limited to, existing physical features and the relocation of the 

Algonquin Gas Transmission pipelines. As part of this feasibility analysis of the NYSDEC 

Proposed Project, this Report supplements and amends the preliminary 2003 Economic and 

Environmental Impacts Associated with Conversion of IPEC Units 2 and 3 to a Closed-Loop 

Condenser Cooling Water Configuration Report (2003 Report), prepared by Enercon Services, 

Inc. (ENERCON). 

ENERCON was retained to further evaluate the potential conversion to closed-loop cooling. 

While different types of cooling towers exist, with varying levels of cost, performance, and 

impacts, the cooling tower configurations that could reasonably be considered for Unit 2 and 

Unit 3 are limited to a single 100% capacity round hybrid cooling tower for each Unit. 

Even with this configuration, several site-specific conditions have been identified at IPEC that 

would challenge the feasibility of the NYSDEC Proposed Project. Such challenges include, but 

are not limited to, the following: 

 As TRC Environmental Corporation concluded, air emissions resulting from operation of 

the cooling towers would exceed the National Ambient Air Quality Standards for PM10

and PM2.5. Saltwater cooling towers of the scale proposed at IPEC would typically be 

expected to produce plume emissions exceeding National Ambient Air Quality Standards 

in non-attainment areas (see discussion of San Onofre Nuclear Generating Station in 

Section 7.2). 

 As Saratoga Associates, Landscape Architects, Architects, Engineers and Planners, P.C. 

concluded, construction of cooling towers at IPEC may be incompatible with New York 

law and policy relating to scenic resources and aesthetic impacts. 

 Archeological concerns have been identified that could affect the excavation schedule 

and, potentially, tower placement. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

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 The required tower configurations do not conform to municipal law, and Village of 

Buchanan officials are on record in opposition to the construction of cooling towers at 

IPEC. As such, required local zoning approvals may be difficult to obtain. 

 The topography of the IPEC site and general space constraints, in conjunction with the 

fact that the elevation of the tower basins must be sufficiently low to prevent damage to 

the condenser tubes, limit the potential locations for cooling towers. Where located, 

approximately 2 million cubic yards of soil and inwood marble bedrock would need to be 

excavated in conjunction with tower construction. This exceeds 50% of the total crushed 

marble sold or used in the U.S. in 2007. Blast removal would be required to excavate 

large quantities of bedrock at the cooling tower locations and in the piping trenches 

outside of the Riverfront area. To avoid prolonged forced outages, blasting operations 

are proposed to occur while both Units are online. For reference, blasting operations 

would produce quantities of broken rock equivalent to between 364 and 518 truck loads 

(20-cubic yard capacity) each day. 

 Excavation in the Riverfront area would intersect groundwater contamination plumes 

containing tritium and strontium, with potential for soil contamination, requiring 

sampling, analysis, handling, and disposal protocols. Additional construction delays 

beyond those identified in this Report may result from these conditions. 

 Algonquin Gas Transmission pipelines currently exist where the Unit 3 tower would be 

constructed, requiring relocation of those facilities within the IPEC site. The Algonquin 

Gas Transmission pipelines supply approximately 50% of the natural gas demand in New 

England, and the pipelines’ owner has emphasized that this supply cannot be interrupted, 

requiring accommodations that may cause further construction delay. This relocation 

also would require Federal Energy Regulatory Commission (FERC) approval. 

 Conversion of the Stations to closed-loop cooling would be an unprecedented 

undertaking that would likely encounter unforeseen challenges during design and 

implementation that are not anticipated or addressed here. 

The total duration of the NYSDEC Proposed Project is expected to extend almost 13 years. This 

schedule includes an 18-month design period before NYSDEC approval, a 36-month permitting 

and licensing period between NYSDEC approval of the project and the start of construction, and 

the expected construction duration of more than eight years, which includes an estimated 42 

weeks of continuous forced outage, conducted simultaneously, at both units. Of the eight-year 

construction schedule, approximately four years would be required for drilling, blasting, and 

spoils removal. This construction timeframe reflects conditions that have arisen since the initial 

2003 conceptual construction schedule, as well as additional analysis of the conditions described 

at that time, including the following: 

 Excavation for the conversion to closed-loop cooling would overlap with areas of known 

radiological groundwater contamination, the remediation of which is currently subject to 

NRC oversight. Development and employment of protocols for sampling, analysis, 

handling and disposal of contaminated soil and water may result in substantial 

construction delays. 

 The relocation of the on-site Algonquin pipelines must be undertaken and completed 

prior to any blasting work performed at the Unit 3 cooling tower location. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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Considering the conceptual nature of the current design parameters, the lack of comparable 

retrofits, and typical unknown conditions that arise in major construction projects, this schedule 

represents a reasonably aggressive scenario. Significantly longer durations than currently 

estimated could result. 

The anticipated direct overnight capital cost for the conversion for both Unit 2 and Unit 3 is 

collectively estimated at a minimum of $1.19 billion. The estimated cost includes relocation of 

the Algonquin Gas Transmission pipelines. As Unit 2 and Unit 3 have net capacities of 1078 

MWe and 1080 MWe, respectively, a 42 week forced outage at both Units 2 and 3, accounting 

for a coincident maintenance outage at one Unit, would result in approximately 14,502,000 

MWhr of lost electrical generation, significantly increasing the overall costs of conversion and 

adverse environmental impacts. A subsequent report will address forced outage costs 

specifically, as well as related impacts.1

As a result of conversion, the Stations would also incur ongoing operational and parasitic 

electrical generation losses. Averaged across the entire year, the combined operational and 

parasitic losses would be approximately 88.2 MWe; however, operational power losses would 

increase to approximately 157.8 MWe during the peak summer power generation season. Again, 

this report does not directly calculate the impacts of lost electrical generation. In addition to 

ongoing operational and parasitic losses, the Stations would also incur annual operations and 

maintenance costs due to the NYSDEC Proposed Project. Annual operations and maintenance 

costs associated with closed-loop cooling at the Stations would be more than $4 million for the 

first five years, with increasing costs in the subsequent years due to the need for increased 

equipment replacement and repair. 

No nuclear stations designed solely for once-through cooling have been converted to closed-loop 

cooling. Conversion of the condenser cooling system of an existing plant presents fundamental 

design problems that result in plant performance impacts or require redesign of the condenser. 

At the Stations, the expected performance impacts could not be mitigated by condenser 

modifications without the complete reconstruction of the turbine building. Moreover, absent any 

practical history of closed-loop cooling retrofits at nuclear facilities, engineering observations 

and conclusions regarding any such conversion must be made on a purely speculative basis and 

are inherently subject to unforeseen challenges during the detailed design phase and the 

subsequent implementation. As such, the cost and schedule estimates presented herein are likely 

understated, representing a lower bound for the cost and durations for the actual project. In 

addition, due to the untried nature of this type of conversion and the intrusive plant modifications 

that would be required, the feasibility of a closed-loop cooling retrofit at a nuclear facility cannot 

be guaranteed at any point in the design stage. Only upon successful operation of a completed 

closed-loop cooling retrofit could this type of conversion be conclusively considered feasible. 

 

1

 Entergy’s legal counsel has directed that forced outage costs be considered, consistent with the Interim Decision, 

under New York’s State Environmental Quality Review Act (“SEQRA”) and/or an economic test not currently 

defined by NYSDEC in a separate assessment, and accordingly need not be addressed now. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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1 Background and Introductions 

1.1 History 

Unit 2 and Unit 3 were each approved for service by the New York Public Service 

Commission in the mid-1970s to meet a demonstrated need for electric power. Both Units are 

pressurized water reactors (PWRs) with net capacities of 1078 MWe and 1080 MWe for Unit 

2 and Unit 3, respectively. Located on the east side of the Hudson River in the Village of 

Buchanan, each Unit utilizes a once-through type condenser cooling water system (i.e., 

circulating water (CW) system), with the intakes from and a shared discharge canal to the 

Hudson River. The design flow rate of the CW system (i.e., CW system capacity) for each 

unit is 840,000 gpm. 

1.1.1 PWR System Operation 

Unit 2 and Unit 3 are Westinghouse four-loop PWRs. PWRs consist of two separate 

systems: a closed, pressurized reactor coolant system (primary system), and a power 

conversion system (secondary system) for the generation of electricity. The basic 

configuration of a typical PWR is shown in Figure 1.1. In the primary system, reactor 

coolant is heated by nuclear fission in the reactor. The primary system operates at high 

pressure to prevent the production of steam in the reactor. The heated reactor coolant is 

used in the steam generators to produce steam in the secondary system. The steam formed 

in the steam generator is transferred by the secondary system to the main turbine generator, 

where it is converted into electricity. After passing through the low pressure turbine, the 

steam is routed to the main condenser, which is operated at a vacuum to allow for the 

greatest removal of energy by the low pressure turbines. The steam is condensed into 

water in the condenser by the flow of circulating water through the condenser tubes. The 

water is then pumped back to the steam generator for reuse. The primary and secondary 

systems are physically separated in the steam generator, minimizing radioisotope transfer 

to the secondary system. 

The power output of the reactor, and the outlet temperature of the reactor coolant, are 

controlled by adjusting several factors which affect the core’s reactivity. The reactor 

control system is designed to avoid nuclear plant transients for prescribed design load 

perturbations. Long-term regulation of the core reactivity is accomplished by adjusting the 

concentration of boric acid in the reactor coolant, while short term reactivity control for 

power changes or reactor trip is accomplished by the movement of control rod clusters 

[Ref. 12.7]. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

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Figure 1.1 Basic Arrangement of a PWR 

1.1.2 Circulating Water System Background 

The circulating water systems for Unit 2 and Unit 3 each consist of six circulating water 

pumps that draw water from the Hudson River and discharge into the inlet water boxes of 

their respective condensers. Each circulating water pump has a design intake flow capacity 

of 140,000 gpm and is housed in an individual well within each unit’s consolidated cooling 

water intake structure (CWIS). Unit 2 and Unit 3 have separate CWISs, each configured 

with central service water intake channels located between three circulating water channels 

on each side. The CWISs contain bar racks that filter debris, and coarse mesh traveling 

water screens that filter fish and residual debris from the intake water prior to the 

circulating water pumps suction. Unit 2 contains six Allis Chalmers dual speed circulating 

water pumps rated at 140,000 gpm at 21 feet total dynamic head (TDH) when running at 

254 rpm, and 84,000 gpm and 15 feet of total dynamic head when running at 187 rpm. 

Unit 3 contains six Allis Chalmers variable speed pumps that are rated for 140,000 gpm at 

29 ft TDH when running at 360 rpm and 84,000 gpm at 19.5 ft TDH when running at 250 

rpm. The circulating water pumps discharge through 84 inch headers to the inlet water 

boxes and the circulating water subsequently passes through the condenser tubes 

condensing steam admitted from the turbines. Flow from the condenser outlet waterboxes 

of Unit 2 and Unit 3 is discharged through 96 inch piping, and combines in the discharge 

tunnel prior to being returned to the Hudson River via the discharge canal. 

1.1.3 Novelty of Closed-Loop Cooling Retrofits 

No nuclear power plant designed for once-through cooling has ever been retrofitted to 

closed-loop condenser cooling. One nuclear power plant, Palisades Nuclear Generating 

Station (PNGS), although initially designed for once-through cooling, was redesigned for 

closed-loop cooling during construction; consequently, the circulating water system 

MSR

Hudson

River 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

3 

components, particularly the condensers, were sized to accommodate the expected heat 

rejection capability provided by cooling towers. 

Absent any practical history of closed-loop cooling retrofits at nuclear facilities, 

engineering observations and conclusions regarding any such conversion must be made on 

a purely speculative basis and are inherently subject to unforeseen challenges, with a 

corresponding, potentially large, degree of uncertainty. Thus, conclusions about 

feasibility, while based on best professional judgment, do not have the benefit of either 

available technology or past efforts at comparable facilities. Due to the untried nature of 

this type of conversion and the intrusive plant modifications that would be required, the 

feasibility of a closed-loop cooling retrofit at a nuclear facility cannot be guaranteed at any 

point in the design stage. Only upon successful operation of a completed closed-loop 

cooling retrofit could this type of conversion be conclusively considered feasible. 

Likewise, only direct comparison to a successful closed-loop cooling retrofit could provide 

reliable basis for cost estimates. For this assessment, cost estimates were done in such a 

way as to minimize the necessary assumptions, and relied instead on well-developed, 

detailed conceptual designs. However, given the absence of any practical applications, 

costs are likely to be understated. 

1.1.4 Conclusions from the 2003 Report 

In 2003, ENERCON performed a preliminary evaluation of the feasibility of converting 

IPEC Units 2 and 3 to closed-loop cooling, and an assessment of the associated economic 

and environmental impacts (see Attachment 1). The 2003 Report concluded that 

conversion of IPEC to closed-loop cooling would be theoretically feasible; however, with 

appreciable elevation changes, a general lack of available space, a subsurface primarily 

composed of solid rock, the location of a major interstate gas pipeline, local air quality, 

archeological and aesthetic considerations, etc., significant site-specific challenges existed. 

This Report further investigates these and other challenges to a closed-loop conversion of 

IPEC. 

There are various methods for heat rejection from a closed-loop cooling system, including 

cooling ponds, canals, and towers. However, the 2003 Report concluded that cooling 

towers would be the only heat rejection method not rendered infeasible by space 

constraints at IPEC. Several cooling tower types were evaluated: natural-draft towers, 

mechanical-draft towers, and hybrid towers. 

Conversion of the condenser cooling system of an existing plant presents fundamental 

design problems. The design of the condenser and turbine is based on the anticipated 

temperature of the condenser cooling water. If the condenser cooling water were not as 

cold as the original once-through design requires for optimal performance, then the 

condenser heat rejection would be reduced and the backpressure on the turbine increased. 

With an increase of backpressure on the turbine, performance is significantly affected, and 

ultimately generator output is reduced. The 2003 Report determined that cooling towers, 

through evaporative cooling, could not match the low temperature of the River intake. In 

the winter months the impact would be lessened, but during the summer performance 

would suffer appreciably. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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Due to IPEC-specific zoning and permitting constraints, a tower with visible plume 

abatement and noise abatement was deemed necessary. Additionally, due to the rocky 

terrain and rapid elevation changes, a tower with a minimum footprint was selected to 

reduce overall excavation and clearing. A single round hybrid cooling tower for each Unit 

was found to most closely meet each Unit’s performance needs. 

A hybrid, also referred to as a “wet/dry” or “plume abated” cooling tower, addresses many 

of the shortcomings of other types of cooling tower, particularly as applies to the IPEC 

site. Basically, a hybrid tower is the combination of the wet tower, with its inherent 

cooling efficiency, and a dry heat exchanger section used to reduce or eliminate visible 

plumes in the majority of atmospheric conditions. After the plume leaves the lower “wet” 

section of the tower, it travels upward through a “dry” section where heated, relatively dry 

air is mixed with the plume in the proportions required to achieve a non-visible plume in 

most circumstances. 

Figure 1.2 illustrates the air flow path through a cell of a parallel path hybrid tower, and 

the applicable simplified psychrometric chart. 

Figure 1.2 Partial Desaturation of Air in a Parallel Path Hybrid Tower 

A hybrid cooling tower is designed to significantly reduce both the apparent density and 

the persistency of the plume. Incoming hot water flows first through the dry heat 

exchanger (finned coil) sections, then through the wet (evaporative cooling) fill section. 

Parallel streams of air flow across the coil sections and through the fill sections, leaving 

the coil sections at dry condition 3, and leaving the fill sections at saturated condition 2. 

These two separate streams of air then mix together going through the fans, along the lines 

3-4 and 2-4 respectively, exiting the fan cylinder at sub-saturated condition 4. This exit air 

then returns to ambient conditions along line 4-1, avoiding the region of super-saturation 

(visible plume) in most cases. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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Figure 1.3 Round Hybrid Tower versus Linear Cell-Type Hybrid Tower

As detailed in the 2003 Report, the round hybrid tower has the following attributes and 

features (see Figure 1.3): 

 The concentrated center plume is not susceptible to recirculation to the tower inlets, 

improving tower performance. Additionally, the center plume is discharged at a 

higher elevation, approximately 165 feet, and reaches significantly greater heights 

due to the flow velocity and thermal concentration created by the central discharge 

shroud. This feature promotes distribution of entrained salts over a much larger area, 

thus lowering local concentrations, and reducing ground level plumes that could 

compromise Station systems, including plant security. 

 The round tower has an appreciably smaller size footprint than an equal capacity 

linear tower. With the high excavation costs at IPEC, the smaller footprint would 

facilitate construction. The round design, at approximately 500 feet in diameter for 

the required capacity for each Unit, compares favorably to a linear tower that could 

approach 1500 feet in length, running parallel to the River shore. 

 Less piping, in a simpler configuration, is required for a round tower. Supply and 

return piping is required for each cooling tower. To provide cooling for either Unit 2 

or 3, a single round tower or a pair of linear towers would be required. In addition to 

the requirement for more towers, linear towers are also subject to more restrictive 

siting requirements. Siting restrictions can significantly increase piping requirements 

due to the need for adequate spacing between towers and also between towers and 

other buildings. 

 Dedicated fans for the dry and wet sections of the round hybrid allows efficient tower 

usage, with the dry section fans operating at reduced capacity when ambient 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

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conditions don’t dictate their usage for plume control. Linear, cell-type hybrid towers 

have a single fan per cell, inducing flow through both sections, hence operate at full 

fan power at all times. 

The conceptual design provided in the 2003 Report balanced the siting of each cooling 

tower against the site terrain and proximity to each Turbine Building to minimize the 

excavation required. Siting was also constrained by the maximum cooling tower basin 

elevation, which was fixed by the maximum pressure allowable through the condenser. 

The cooling tower supply and return piping was also concentrated into two 122-inch and 

two 144-inch concrete lined steel pipes for each cooling tower to minimize the excavation 

required and reduce capital costs. 

Because any changes to the condenser cooling systems would involve the very heart of the 

plant, construction in the Riverfront area and tie-in with the condenser cooling systems 

would have to be completed with both Units in a forced outage. Although much of the 

excavation work and cooling tower erection could be done pre-outage, new circulating 

water pumping stations and changes to the common discharge canal force a major outage. 

1.2 Purpose and Scope of this Report 

Although the existing once-through circulating water scheme provides both the lowest cost 

method of condenser cooling and supports the highest level of Station capacity, IPEC has 

been required by the NYSDEC to further evaluate possible conversion of the existing system 

to a closed-loop circulating water system configuration. The overall purpose and scope of this 

Report is to determine feasibility of the NYSDEC Proposed Project and, also, update the 2003 

Report in order to achieve a higher measure of certainty, with appropriate defined ranges, for 

the costs of retrofitting with closed-loop cooling and the schedule for doing so. This includes 

further development of the initial conceptual design to a level of detail commensurate with 

more accurate subsequent cost estimates, updating the previously estimated construction and 

procurement costs to the current dollar value, addressing additional impacts and new site 

conditions identified since the 2003 Report, and updating construction costs and outage 

schedules to account for additional analysis performed since the original report submittal. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

7 

2 Conceptual Design 

As discussed in Section 1.1.3, there have been no conversions of existing operating nuclear 

stations from once-through to closed-loop cooling. Due to this uncertainty, an investigative 

analysis on the impact of closed-loop cooling on plant systems, operation, and electrical output 

must be considered. Conversion to closed-loop cooling would represent a massive and difficult 

engineering and construction undertaking. 

Three design alternatives are considered for closed-loop cooling at IPEC: (1) retrofit both Units 

to closed-loop cooling, (2) retrofit only Unit 2 to closed-loop cooling, or (3) retrofit only Unit 3 

to closed-loop cooling. Conceptual designs, including major plant modifications, have been 

developed for all three alternatives consistent with the conclusions of the 2003 Report (Section 

1.1.4). The conceptual designs are based on summary level scope intended to identify challenges 

and predict budgetary costs. 

2.1 Conversion of Unit 2 and Unit 3 

The conversion of both Units 2 and 3 to closed-loop cooling would require the installation of 

two 100% capacity round hybrid cooling towers and the associated piping and equipment 

(Attachment 1). The cooling towers would need to be placed to the northeast and southwest 

of the Stations, as shown in Attachment 2, Sketch ENTGNU011-SK-001. Construction of the 

Unit 3 cooling tower would require relocation of the Algonquin Gas Transmission pipelines, 

as discussed in Section 4. Each cooling tower would be approximately 165 feet tall and 525 

feet in diameter (Attachment 1). 

2.1.1 Circulating Water System Piping 

The new circulating water piping would need to be routed from new circulating water 

pumps to the cooling towers and back to the condenser. The cooling tower supply piping 

would need to be two 120-inch (10 feet) diameter concrete-lined steel pipes (AWWA 

Specification C200 and C205) per Unit. Gravity-driven flow from the cooling tower basin 

to the condenser would need to be via two 144-inch (12 feet) diameter concrete-lined steel 

pipes (AWWA Specification C200 and C205) per Unit. 

Retrofitting a nuclear power plant from a once-through cooling design to closed-loop 

cooling has not occurred; therefore, there is a large degree of uncertainty in the operation 

of any closed-loop cooling retrofit. The startup, steady-state operation, and shutdown of 

the closed-loop cooling system would require balancing the circulating water flow between 

the cooling tower basin and the discharge canal reservoir. The control scheme would 

require a programmable logic control system and redundant instrumentation, and be 

capable of balancing the closed-loop cooling equipment to meet ambient environmental 

conditions, plant operational requirements, and maintain adequate inventory each basin. 

2.1.1.1 Pipe Routing / Interferences 

The new Unit 2 circulating water pump house would need to be located on the existing 

discharge canal between the Unit 1 and Unit 3 turbine-generator buildings, as shown in 

Attachment 2, Sketch ENTGNU011-SK-001. Also shown in Attachment 2, Sketch 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

8 

ENTGNU011-SK-001, the cooling tower supply piping would need to be routed from the 

new pump house to the Unit 2 cooling tower through the “Riverfront”, the space between 

the intake structures and turbine-generator buildings of each Unit. There are several 

underground utilities present in the Riverfront area, the most significant of which is the 

Unit 2 service water and existing circulating water supply piping and electrical duct 

banks. Furthermore, this area is commonly used for vehicular traffic and is part of the 

heavy load path (i.e., the road must withstand loads up to 300 tons). Therefore, the 

supply and return piping would need to be buried to sufficient depth beneath the road 

elevation and backfilled to support the current traffic patterns and the resultant structural 

loads. Outside the protected area (i.e., outside the graded and paved Riverfront area), the 

piping would need to be routed to the cooling towers following approximately the same 

gradient as the surface elevation, providing a minimum of 10 feet depth of cover (see 

Attachment 2, Sketch ENTGNU011-SK-002). 

Routing the piping from the Riverfront area to the Unit 2 cooling tower basin presents 

significant challenges. The piping elevation would rise approximately 15 feet between 

the Riverfront area and the Unit 2 cooling tower basin, following the gradient of the 

surface elevation, and excavation of the bedrock would be required. The drainage areas 

created by the construction of the Independent Spent Fuel Storage Installation (ISFSI) 

would also create challenges for the Unit 2 pipe routing. These areas would either need 

to be avoided or moved to appropriate locations consistent with the drainage 

requirements of the ISFSI. 

The new Unit 3 circulating water pump house would need to be located on the existing 

discharge canal near the end, as shown in Attachment 2, Sketch ENTGNU011-SK-001. 

The cooling tower supply piping would need to be routed almost directly southeast to the 

Unit 3 cooling tower. Both the cooling tower supply and return pipes would need to be 

routed to the cooling towers following approximately the same gradient as the surface 

elevation, providing a minimum of 10 feet depth of cover (see Attachment 2, Sketch 

ENTGNU011-SK-003). Inside the protected area, the cooling tower return piping would 

need to be routed to the Unit 3 condenser through the Riverfront area between the Unit 3 

turbine-generator building and intake structure. Similar to the Unit 2 routing, the Unit 3 

pipes would need to be buried to accommodate current traffic and access patterns and to 

avoid many underground utilities, including the existing Unit 3 service water piping. 

Installation of the new circulating water piping in the Riverfront area would require an 

outage of both Units. Several safety-related systems would still require offline cooling 

(e.g., Spent Fuel Pool, Emergency Diesel Generators); however, the existing service 

water supply would be interrupted by excavation under and around the service water 

piping. Each safety-related system requiring offline cooling would need to be reviewed 

and provided with secondary cooling. Additional security would also be required during 

construction within the protected area. 

2.1.1.2 Tie-In Locations 

The Unit 2 cooling tower return piping would tie-in to the existing Unit 2 CW piping in 

the Riverfront area prior to flowing through the condensers, as shown in Attachment 2, 

Sketch ENTGNU011-SK-004. Each cooling tower return pipe would supply three 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

9 

existing CW pipes. One cooling tower return pipe would be routed at centerline 

elevation 1’-0” above MSL through the Riverfront to tie-in to the three northernmost 

existing CW pipes. The 1’-0” centerline elevation would allow a 7.5’ depth of cover. 

The other cooling tower return pipe would be routed at centerline elevation (-) 11’-0” 

below MSL through the Riverfront to pass underneath the exiting service water piping at 

centerline elevation 1’-0” above MSL, with 5’ of clearance between pipes. After clearing 

the existing service water piping, the cooling tower return line rises to centerline 

elevation 1’-0” above MSL to connect to the three southernmost existing CW pipes. A 

header would be required at the end of each cooling tower return line to connect to the 

existing CW pipes at centerline elevation 6’-6” above MSL. A throttling valve would be 

required after the tie-in on each existing CW pipe to regulate flow to each condenser 

waterbox and allow for condenser maintenance. 

The Unit 3 cooling tower return pipes would tie-in to the existing Unit 3 CW pipes in the 

Riverfront area prior to flowing through the condensers, as shown in Attachment 2, 

Sketch ENTGNU011-SK-007. Each cooling tower return pipe would supply three 

existing CW pipes. One cooling tower return pipe would be routed at elevation 1’-0” 

above MSL through the Riverfront to tie-in to the three southernmost existing CW pipes. 

The 1’-0” elevation would allow a 7.5’ depth of cover. The other cooling tower return 

pipe would be routed at centerline elevation (-) 11’-0” below MSL through the Riverfront 

to pass underneath the exiting service water piping at centerline elevation 1’-0” above 

MSL, with 5’ of clearance between pipes. After clearing the existing service water 

piping, the cooling tower return line would rise to centerline elevation 1’-0” above MSL 

to connect to the three northernmost existing CW pipes. A header would be required at 

the end of each cooling tower return line to connect to the existing CW pipes at centerline 

elevation 6’-6” above MSL. A throttling valve would be required after the tie-in on each 

existing CW pipe to regulate flow to each condenser waterbox and allow for condenser 

maintenance. 

The new circulating water pumps for each Unit would draw suction from the modified 

discharge canal to supply water to the cooling tower supply pipelines. In its modified 

configuration, the discharge canal would no longer serve its once-through cooling 

function to return circulation water to the Hudson River and would become the new 

circulating water pump pit. The new Unit 2 pump house would be located on the 

discharge canal between the Unit 1 and Unit 3 turbine generator buildings. The new Unit 

3 pump house would be located on the discharge canal along the Hudson River bank. 

Additional details on how closed-loop cooling would require reconfiguration of the 

discharge canal are provided in Section 2.1.3. 

2.1.2 Intake Structure 

Although the existing circulating water pumps and screens would no longer be required for 

closed-loop operation, service water flow would still be maintained through the existing 

intake structures. The discharge from the service water systems would be used after a 

conversion to closed-loop cooling for makeup water to the cooling towers. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

10 

2.1.2.1 Closed-Loop Operation 

The makeup water flow rate required to support closed-loop cooling would vary based on 

Hudson River water quality and meteorological conditions as further discussed in Section 

7.1. In addition, the closed-loop cooling start-up sequence would require a large amount 

of makeup water to charge the system. All makeup and start-up flow would be supplied 

to the discharge canal to provide adequate flow to the new circulating water pumps. 

Under typical operation, the makeup water flow would be provided to the Unit 2 and Unit 

3 reservoirs by the service water discharge. An ancillary makeup pump (shown in 

Attachment 2, Sketch ENTGNU011-SK-007) would provide additional makeup flow 

directly to the Unit 2 reservoir under conditions when the total required makeup flow 

exceeds the service flow discharged by both Units. The additional flow from the makeup 

pump would flow over the weir between the Unit 2 and 3 pump reservoirs to provide 

flow to the Unit 3 pump reservoir. The ancillary pump would also likely be used during 

the closed-loop start-up sequence. The blowdown flow plus any excess service water 

flow would be discharged through the Unit 2 and Unit 3 reservoir weirs. 

Additional operational procedures would be required to ensure flow balance throughout 

the closed-loop cooling system. As a result, conversion of IPEC to closed-loop cooling 

would increase the complexity of plant operations and require additional operations 

personnel. 

2.1.2.2 Current Equipment to Remain Under Closed-Loop Operation 

The current intake structures are divided into separate channels for each of the six 

circulating water pumps with a center channel shared by the six service water pumps as 

shown in Figure 2.1. Each of the circulating water pump channels is served by a 

Ristroph-type traveling water screen and the service water pump channels have two 

Ristroph-type traveling water screens.2

 

2

 A full description of the Ristroph-type traveling water screens is included in Section 2.3.1.1 of the Evaluation of 

Alternative Intake Technologies at Indian Point Units 2 & 3 [Ref. 12.8], submitted with this Report. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

11 

Figure 2.1 Plan View of the Unit 2 (Left) and the Unit 3 (Right) CWISs 

Due to the need to maintain the existing safety-related service water systems, four 

traveling water screens, two at each Unit, would need to be retained. 

2.1.3 Discharge Canal 

In order to convert Units 2 and 3 to closed-loop cooling, multiple modifications to the 

discharge canal would be required, as discussed in Sections 2.1.3.2 through 2.1.3.6. The 

existing discharge canal would need to be modified to serve as a reservoir/pump pit for the 

twelve new circulating water pumps that would supply the cooling towers. A weir would 

be installed to separate the Unit 2 and Unit 3 pump reservoirs, as shown in Attachment 2, 

Sketch ENTGNU011-SK-007. The new reservoirs would provide some operational 

flexibility, whereby the reserve volume in each reservoir acts as a buffer against flow 

disruptions and equipment failure. The technical and logistical challenges associated with 

this design are discussed in the following sections. 

2.1.3.1 New York State Energy Research and Development Authority 

Discharge Canal Ownership 

Entergy’s counsel has advised that conversion of IPEC to closed-loop cooling may 

increase the appraised value of the area of the discharge canal leased from the New York 

State Energy Research and Development Authority (NYSERDA) and thus increase the 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

12 

discharge canal rent obligations upon renewal of the lease in March 2017 above the 

current annual cost of approximately $1.0 million. 

2.1.3.2 Pump Submergence Modification 

New Unit 2 and Unit 3 pump houses would need to be constructed on the existing 

discharge canal, near the Unit 3 turbine-generator building and along the Hudson River 

bank, respectively. The conceptual pump house locations are shown on Sketch 

ENTGNU011-SK-001 in Attachment 2. 

In order to provide the necessary flow to the cooling towers, the new circulating pumps 

would need to be approximately 45 ft long. Providing the correct submergence of the 

pump is necessary for continuous closed-loop operation, whereby inadequate 

submergence would cause damage to the pumps, render the circulating water system 

inoperable, and cause the plant to trip offline. The required submergence value of these 

pumps would necessitate excavation to increase the depth of the existing discharge canal 

in the locations of the new pump houses. The new depth at elevation (-) 32’-5” under the 

Unit 2 pump house would slope up gradually to meet the existing canal depth at elevation 

(-) 17’-0” below mean sea level (MSL). The existing canal depth in the Unit 3 pump 

house location at elevation (-) 20’-0” would require less excavation. This design 

maximizes the water inventory margin available above the minimum required 

submergence level of the pumps (Attachment 1). The minimum required submergence 

would be reached when the water level dropped from the nominal elevation of (+) 1’-0” 

above MSL to (-) 14’-0” below MSL. This level would need to be reached in the Unit 2 

and Unit 3 reservoirs after approximately 4 to 6 minutes if supply to the reservoirs was 

suddenly cut off. Once the water level has dropped below the minimum required 

submergence, the circulating water pumps would no longer be capable of pumping water 

from the reservoirs to the cooling towers. A weir would need to be installed in the 

existing discharge canal prior to converging with the Unit 3 discharge tunnel outlet, as 

shown in Attachment 2 Sketch ENTGNU011-SK-007, to separate the reservoirs for each 

Unit and prevent an inventory drop in one reservoir from affecting the other. 

2.1.3.3 Reservoir Capacity 

Modifications would be required to convert the existing discharge canal to serve as the 

Unit 2 and Unit 3 pump reservoirs. These modifications would include increasing the 

depth of the canal beneath the new pump houses to accommodate new circulating water 

pumps, adding a weir prior to converging with the Unit 3 discharge tunnel outlet, as 

shown in Attachment 2 Sketch ENTGNU011-SK-007, to separate the Unit 2 and Unit 3 

pump reservoirs. After modifications, the Unit 2 and Unit 3 reservoirs would hold over 

4.2 million and 6.5 million gallons, respectively. 

2.1.3.4 Offline Effluent Flow 

Flow from each Unit’s discharge tunnel would need to be rerouted directly to the Hudson 

River, using temporary piping, to maintain dry construction conditions in the existing 

discharge canal for modification to new pump reservoirs. Routing of temporary piping 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

13 

would be difficult due to the fact that the discharge tunnel is rectangular in shape, with 

the outlet piping into the discharge tunnel prior to flowing into the discharge canal. 

Even though construction in the Riverfront area would require an outage of both Units, 

several safety-related systems would still require offline cooling (e.g., Spent Fuel Pool, 

Emergency Diesel Generators). Each of these systems would need to be reviewed and 

secondary cooling provided. Discharge from these secondary cooling systems would 

need to be returned directly to the Hudson River via temporary piping. 

2.1.3.5 Groundwater Contamination 

As discussed in Attachment 3, groundwater, currently subject to NRC regulatory 

oversight because of the presence of radiological contamination (primarily tritium (H-3) 

and strontium (Sr-90)), migrates through a portion of the expected cooling tower 

excavation area. GZA GeoEnvironmental, Inc. (GZA), an environmental and 

geotechnical consulting firm, developed groundwater contamination plume models for 

tritium and strontium based on quarterly groundwater sampling and elevation 

measurements taken at various monitoring points, as well as the analyses summarized in 

previous Quarterly Reports and the Conceptual Site Model presented in the final 

Hydrogeologic Site Report [Ref. 12.14]. According to GZA, sampling and analysis 

protocols for groundwater and excavated material would be developed and employed to 

manage site work and determine appropriate handling and disposal requirements (see 

Attachment 3). 

Further, during the excavation process discussed in Section 6, excavation would be 

required at depths well below the groundwater table in the contaminated areas. To 

maintain dry conditions required for pipe construction and backfilling, contaminated 

groundwater would need to be continually pumped from the excavation area below the 

groundwater table (i.e., dewatering). As described in Attachment 3, absent careful 

management, dewatering could cause the groundwater to migrate from contaminated 

areas to clean areas, altering the existing radionuclide plume. To control spreading, 

dewatering from within contaminated groundwater areas would have to begin prior to 

excavation in the contaminated area, but coincident with excavation and dewatering in 

the adjacent clean areas. This dewatering would also have to be continued until 

completion of the excavation. 

As discussed in Attachment 3, groundwater may contain tritium, strontium, and 

potentially smaller concentrations of other radionuclides, including cesium, that would 

have to be disposed of. GZA analyzed several disposal options and concluded that the 

only feasible method of disposal would be discharge directly to the Hudson River 

(Attachment 3). GZA has been advised by Entergy’s legal counsel that NYSDEC 

appears to believe they have jurisdiction of discharge to the Hudson River. GZA 

concluded, therefore, that disposal options are limited. 

2.1.3.6 Low Volume Waste Effluents 

Conversion to closed-loop cooling would have engineering and operational impacts on 

the liquid waste disposal system regulated by NRC. With respect to radiological 

materials, discharge streams are managed consistent with 10 CFR 20 dose limits and to 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

14 

ensure consistency with 10 CFR 50 design objectives for keeping potential exposure 

levels as low as is reasonably achievable (ALARA). Likewise, discharge of nonradioactive material (i.e., boron, chlorine, etc.) is authorized and governed by the SPDES 

permit [Ref. 12.20]. Both are managed in the existing liquid waste disposal system. 

Conversion to closed-loop cooling would require significant changes to the existing 

liquid waste disposal system, any of which would require reconsideration and/or revision 

of plant operating procedures and the operating margins to current regulatory limits. 

Therefore, a thorough review of the final design under 10 CFR 50.59 would be required 

to ensure compliance with 10 CFR 50 ALARA practices and 10 CFR 20 dose and release 

rate limits, as well as environmental reviews of SPDES permit limitations for nonradioactive releases. 

2.2 Conversion of Only Unit 2 

Conversion of Unit 2 to closed-loop cooling would require the installation of one 100% 

capacity round hybrid cooling tower and the associated piping and equipment as described in 

the 2003 Report (Attachment 1). The cooling tower would need to be placed to the northeast 

of the Unit Containment Building, as shown in Attachment 2, Sketch ENTGNU011-SK-002. 

The closed-loop cooling design of only Unit 2 would be identical to that discussed in Section 

2.1 without the modifications to Unit 3. 

2.3 Conversion of Only Unit 3 

Conversion of Unit 3 to closed-loop cooling would require the installation of one round 

hybrid cooling tower and the associated piping and equipment as described in the 2003 Report 

(Attachment 1). The cooling tower would need to be placed to the southwest of the Unit 3 

Containment Building, as shown in Attachment 2, Sketch ENTGNU011-SK-003. 

Construction of the Unit 3 cooling tower would require relocation of the Algonquin Gas 

Transmission pipelines, as discussed in Section 4. The closed-loop cooling design of only 

Unit 3 would be identical to that discussed in Section 2.1, whereby the only modification to 

Unit 2 would be additional piping to transport Unit 2 low level effluents to the Unit 3 

discharge point. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

15 

3 Station Operational Parameters 

Unit 2 and Unit 3 are water-dependent – meaning both that they require a specific quantity and 

temperature of water. The Stations were designed for and currently utilize the consistently cold 

brackish water from the Hudson River for operation. Specifically, the main steam condensers at 

both Units were designed to operate over the fixed range of circulating water inlet temperatures 

provided by the Hudson River. Deviation beyond this range impacts plant performance. 

Conversion of IPEC to closed-loop cooling would reduce access to the relatively cold Hudson 

River water and increase the circulating water inlet temperature to the main condensers. 

Therefore, the impact of this increase to circulating water temperature on plant systems, 

operation, and output must be evaluated. 

Conversion of a nuclear power plant designed for once-through cooling to closed-loop cooling 

has never occurred (Section 1.1.3). As such, the following analysis is theoretical, and while 

benchmarked against actual plant data, is not reflective of any history of operation of a nuclear 

power plant converted to closed-loop cooling. Subject to these limitations, the theoretical 

impacts on Units 2 and 3 due to conversion from once-through to closed-loop cooling are 

evaluated herein. 

This evaluation of closed-loop cooling is performed using a state-of-the-art site performance 

evaluation of power system efficiency (PEPSE) model that accurately predicts and provides plant 

operational parameters and power reductions associated with conversion of IPEC to closed-loop 

cooling. PEPSE is used across the nuclear power industry, as well as the power industry as a 

whole, and is the standard analytical tool to model “what if” scenarios to determine system 

impacts of altering power plant operation. The PEPSE model is designed for each Unit’s actual 

configuration and performance, and used to benchmark theoretical plant performance against 

measured data to provide an accurate summary of the expected results of conversion to closedloop cooling. Similar to the methodology employed in the 2003 Report, an analysis was done 

over the range of expected circulating water inlet temperatures to determine plant performance; 

however, the current analysis utilizes an updated PEPSE model to account for modifications to 

each Unit and was performed using a much larger set of discrete input parameters to increase 

precision. 

3.1 Administrative/Operating Limits 

The Stations’ equipment operation is governed by a set of administrative limits3 used to 

ensure safe and reliable operation of each Unit. Specifically, PWRs are subject to nuclear 

safety constraints on operations of various Station equipment, including pump net positive 

suction head requirements, overall plant control characteristics, core thermal power limits, 

and core thermal-hydraulic stability. The Stations’ equipment operation must be thoroughly 

analyzed in regard to the modifications likely required to convert Unit 2 and 3 from oncethrough to closed-loop cooling, in order to ensure these administrative limits are not 

exceeded. 

 

3

 Administrative limits are limits used to prevent encroachment of NRC licensed limitations (e.g., technical 

specification limitations, FSAR limitations, etc.) and equipment operational limits. They represent practical limits 

for safe and reliable plant operation. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

16 

Changes to the Stations’ cooling water equipment to offset the losses associated with 

conversion to closed-loop cooling are restricted by the size and configuration of the 

equipment within the Turbine Building, particularly the condenser and the surrounding 

components. The main condensers were sized to reflect the use of a stable and cold inlet 

water source (i.e., water drawn from the Hudson River). In order to maintain current 

operational efficiencies, a drastic modification of the condenser (through a size increase) 

would be required; however, due to the physical constraints of the Turbine Building, a 

significant size increase of the condensers is not possible without the complete reconstruction 

of the turbine building. A condenser / turbine building modification of this magnitude would 

be unprecedented (i.e., implementation of a condenser redesign of this magnitude has never 

occurred at an operational nuclear power plant). Due to the magnitude of this redesign, the 

lack of any history of a nuclear plant undertaking such a modification, and the physical 

constraints of the Unit 2 and Unit 3 Turbine Buildings, it is concluded that modification of the 

current cooling water equipment to compensate for the expected power generation would not 

be able to offset the losses associated with conversion to closed-loop cooling. 

The administrative limits given in the Alarm Response Procedures [Ref. 12.15; Ref. 12.16] 

require that the main condenser vacuum be above approximately 3.92 and 4.92 in-Hg for 

Units 2 and 3, respectively.4

 These administrative limits, while considered in the PEPSE 

analysis, were not projected to be exceeded based on historical meteorological conditions. 

3.2 Closed-Loop Operational Efficiency (PEPSE Analysis) 

As discussed in the 2003 Report (Attachment 1), closed-loop cooling performance is based on 

the ambient meteorological conditions, with the result that operational losses at the Stations 

would vary based on seasonal wet-bulb temperature at IPEC. The wet bulb temperature is a 

meteorological measurement which incorporates both moisture content and temperature of the 

ambient air. Local meteorological data was obtained, reviewed, and analyzed for use as an 

input to the PEPSE models for each Unit. The PEPSE model uses, among other things, 

cooling water intake temperature and flow rates to accurately calculate plant operational 

parameters and the resulting net power generated. The PEPSE model provides the expected 

plant operational parameters and power reductions necessary to theoretically operate IPEC 

Units 2 and 3 without exceeding equipment limitations and/or resulting in nuclear safety 

considerations. It should be noted that conversion of a nuclear power plant designed for oncethrough cooling to closed-loop cooling has never occurred and as such, the following analysis 

is theoretical. Although benchmarked against actual plant data, the analysis is not reflective 

of any closed loop conversion of a nuclear power plant. 

 

4

 The pressure setpoints listed in the Alarm Response Procedures [Ref. 12.15; Ref. 12.16] are 25 and 26 in-Hg 

absolute for Units 2 and 3, respectively. Subtracting each of these setpoints from a standard atmospheric pressure of 

29.92 in-Hg results in the main condenser vacuum setpoints of 3.92 and 4.92 in-Hg for Units 2 and 3, respectively. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

17 

3.2.1 Cooling Tower Efficiency / PEPSE Analysis 

The IPEC PEPSE models were reviewed and run to produce the results discussed herein.5

A diagram of the IPEC PEPSE model has been included in Attachment 4, Figures 4-1 

through 4-12. 

3.2.1.1 Meteorological Data Analysis 

The performance of any closed-loop cooling water system is primarily driven by the 

ambient weather conditions at the site and the baseline inlet water temperature values. 

Cooling towers define their performance via an approach to wet bulb temperature. The 

wet bulb temperature is necessary for closed-loop cooling analysis, as cooling towers 

utilize an evaporative process to remove heat from the continuously recirculated cooling 

water. The approach to wet bulb describes the number of degrees above the ambient wet 

bulb temperature by which the cooling tower can be expected to reduce the cooling water 

temperature, whereby a lower approach equates to lower cooling water temperature 

exiting the cooling tower. The approach to wet bulb is a value that is based on the size 

and efficiency of the cooling tower, and essentially represents the cooling ability of the 

equipment. Although wet bulb temperature is not measured directly by site 

meteorological instruments, wet bulb temperature was calculated using dry bulb 

temperature and dew point temperature, both of which are measured onsite. 

Any data set used to predict the performance of the Stations relies heavily on the 

presence of either wet bulb temperature measurements or a combination of values that 

can be used to calculate the wet bulb temperature (e.g., dry bulb temperature and relative 

humidity, dry bulb temperature and dew point, etc.). Entergy provided eight years of 

meteorological data (2001-2008) and a thorough review was conducted to normalize the 

data, ensuring that a uniform data set with no erroneous data is used as the basis for 

analysis. Particular focus was paid to the review and acceptance of the meteorological 

data, as even minor errors present in the meteorological data would propagate throughout 

the analysis. Furthermore, there is almost always some degree of data loss associated 

with meteorological monitoring. This data loss may be due to a number of causes 

(equipment failure, biological/human error, etc.). A general guideline for meteorological 

data acceptance is that the data maintain an average 90% data recovery rate [Ref. 12.35]. 

The average recovery rate for the eight year period analyzed (2001-2008) was 97.2% as 

shown in Attachment 4, Table 4-1; therefore, the data provided by IPEC greatly exceeds 

the threshold for validity and represents an extremely robust data set. 

3.2.1.2 Inlet Water Data Analysis 

Entergy supplied eight years (2001-2008) of average daily inlet water temperatures. This 

data was reviewed to ensure that a uniform data set with no erroneous data is used as the 

basis for analysis. The average recovery rate for the eight year period analyzed was 

 

5

 While finalizing the Report analysis, updated versions of the IPEC PEPSE models were again developed by 

Entergy. The new models were reviewed and compared to the PEPSE models originally used for this Report. It was 

determined that while previous updates were substantial, the most recent updates to the PEPSE model were less 

substantial and would not result in any significant differences in the analysis. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

18 

99.8%, representing an extremely robust data set. The monthly recovery rate per year is 

shown in Attachment 4, Table 4-2. 

3.2.2 Closed-Loop Losses 

Conversion of the Stations to closed-loop cooling would introduce both ongoing 

operational efficiency losses associated with operating beyond the original condenser 

design conditions and parasitic losses associated with the operation of the pumps and 

cooling tower fans. If the effect of closed-loop conversion on plant operation is averaged 

across the entire year, operational power losses would account for a loss in power 

generation of approximately 11.1 MWe and 4.7 MWe at Units 2 and 3, respectively; 

however, operational power losses would peak during the warmest temperature and highest 

dewpoint conditions, when electricity demand is at its highest. Over the historical data 

analyzed (2001-2008), the peak combined operational power loss occurred on June 7th, 

2008 at 2PM, and accounted for a combined operational power loss of 85.4 MWe. 

Additional parasitic losses from the circulating water pumps and the cooling tower fans 

and booster pumps would add an additional 36.1 MWe per Unit in power generation 

losses. Summing the operational and parasitic losses, Units 2 and 3 combined would 

experience an average power generation loss of 88.0 MWe and peak summer power 

generation loss of 157.6 MWe. 

3.2.2.1 Operational Losses 

After review and benchmarking, the IPEC PEPSE model was run over a theoretical 

bounding range of CW inlet temperatures to calculate the baseline closed-loop operation 

of the Stations (i.e., the performance of the Stations if converted to closed-loop 

operation). The PEPSE model allows for the calculation of system outputs and 

operational conditions as a direct function of various system inputs. Because these 

system outputs are fixed, the PEPSE model is limited to the unidirectional calculation of 

operational conditions via system input. To evaluate performance in the full range of 

operating conditions, the net thermal input (MWt) for the system was iterated over a 

series of CW inlet temperatures to find the closest parameters and linearly interpolate 

between them to calculate the system output and operational conditions (i.e., net power 

generated (MWe), hotwell temperatures (°F)/condenser backpressures (in-Hg) for each 

main condenser shell, and the condenser output temperatures (°F)). Overall, the CW inlet 

temperature for each hour is input across a set of data spreadsheets, which in turn allows 

for the calculation of the limiting operational parameters. 

As the operation of cooling towers is driven primarily by ambient environmental 

temperatures, seasonal and daylight conditions have a significant impact on IPEC closedloop operation (see Attachment 4, Sections 4 and 5). The average closed-loop cooling 

operational losses on a yearly basis, including the monthly operational power losses that 

would be incurred at each Unit, are provided in Attachment 4, Section 3. Table 3.1 

presents the average continuous power generation losses that would be incurred at each 

Unit if the Stations were to be converted to closed-loop cooling. Since closed loop power 

loss is the difference in power generation from once-through to closed-loop cooling, the 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

19 

months with the highest average power loss, May and June, are those with the largest 

River water to ambient wet-bulb temperature differential. 

Table 3.1 Unit 2 and Unit 3 Average Continuous Closed-Loop 

Cooling Power Generation Losses 

Month 

Power Loss (MWe) 

Unit 2 Unit 3 

January 5.7 0.1 

February 5.3 0.1 

March 8.2 0.2 

April 15.8 3.2 

May 20.8 9.4 

June 19.3 13.6 

July 9.8 8.5 

August 6.2 5.6 

September 7.6 6.0 

October 12.2 6.1 

November 14.1 3.4 

December 7.9 0.4 

Average Annual 11.1 4.7 

As shown in Table 3.1, the overall effect of a closed-loop conversion on plant operation, 

examined using the IPEC PEPSE models would be an average continuous loss in power 

generation of approximately 11.1 MWe and 4.7 MWe at Units 2 and 3, respectively (15.8 

MWe, total); however, power loss would vary both seasonally and intraday, dependent on 

the difference between River water and ambient wet-bulb temperature. Over the historical 

data analyzed (2001-2008), the peak combined operational power loss of 85.4 MWe 

occurred on June 7th, 2008 at 2PM, when electricity demand was at its highest. 

3.2.2.2 Parasitic Losses 

In addition to the operational losses, the new cooling towers and equipment would 

require an appreciable amount of power to operate (i.e., parasitic losses) which would 

effectively reduce each Unit’s output power. The cooling towers selected for closed-loop 

operation of the Stations are round hybrid cooling towers, designed with noise and plume 

abatement features. In particular, round hybrid cooling towers require significant 

additional electrical loads since they utilize two fans per cell to draw air in through both 

the wet and dry sections of the cooling tower. 

Also, the new circulating water pumps for closed-cycle cooling would require more 

power than the existing circulating water pumps. The additional power required over the 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

20 

existing circulating water pump requirements would be another parasitic loss associated 

with conversion to closed-loop cooling. 

The parasitic losses associated with each component of closed-loop cooling would be as 

follows: 

 Cooling Towers (26.5 MWe per Unit) 

o 44 wet fans (300 HP) 

o 44 dry fans (350 HP) 

o 4 booster pumps (61,250 gpm at 26 ft) 

 Additional Circulating Water Pump Load (9.6 MWe per Unit) 

o 6 circulating water pumps (117,000 gpm at 72 ft) 

Summing the additional parasitic losses from the circulating water pumps and the cooling 

tower fans and booster pumps would be approximately 36.1 MWe per Unit, or a 

combined parasitic loss of 72.2 MWe. Whenever a Unit would be online, these parasitic 

losses would continually draw from the net generating electricity. 

3.2.2.3 Electrical Distribution Effects 

Using the Electrical Transient Analyzer Program (ETAP) software, Attachment 5 

provides a model of the anticipated electrical distribution system required to support the 

conversion of Units 2 and 3 to closed-loop operation. This analysis accounts for the 

expected electrical parasitic losses due to the new components required for closed loop 

operation at both Unit 2 and Unit 3 to determine if extensive improvement to the 

electrical distribution system would be required. 

Reviewing the one line diagrams of this study, the available fault current at the Buchanan 

138kV switchyard bus by the IPEC grid contribution is 16.73 kA . The additional loads 

added by conversion to closed-loop cooling would increase this available fault current by 

1.75kA, or approximately 10%. Per discussions with site personnel, the Buchanan 

138kV switchyard bus has a capacity rating in the order of 60kA, supplying significant 

margin against a short-circuit event. Due to the magnitude of this margin, and due to the 

relatively small increase of load, no modifications to the switchyard would be expected 

by conversion of IPEC to closed-loop cooling; however, additional electrical distribution 

analysis and consideration of the available protective devices ratings would be required in 

the detailed design phase to competely ensure adequate margin is present. Conversion of 

Unit 2 or Unit 3 individually to closed-loop cooling would impact the electrical 

distribution system to a lesser degree then conversion of both Units, and as such this 

analysis is bounding for each individual conversion scenario. Additional details on the 

electrical analysis conducted are included in Attachment 5. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

21 

4 Algonquin Pipeline Relocation 

Due to physical site constraints and water flow requirements, the Unit 3 cooling tower must be 

located on the southwest portion of the IPEC site, as discussed in Section 2.1 and shown in 

Attachment 2 Sketch ENTGNU011-SK-001. However, a portion of this location overlaps the 

existing right-of-way (ROW) for the Algonquin Gas Transmission (Algonquin) pipelines. In 

order to accommodate excavation and construction of a cooling tower for Unit 3, the existing 

pipelines would have to be relocated within the IPEC site, pursuant to the terms of the pipeline 

easement. Spectra Energy Transmission, LLC (Spectra), owner and operator of the Algonquin 

pipelines, has preliminarily evaluated the feasibility of the required relocation (Attachment 6). 

The preliminary timeline for relocating the pipelines is approximately 24 months and the 

estimated cost is approximately $13.8 million, with an accuracy level of (-)25% to (+)40%. The 

feasibility evaluation considers design, permitting, material, labor, and construction, but does not 

include the cost and schedule of spoils removal, which would significantly increase the estimated 

cost provided by Spectra. 

4.1 Pipeline Configuration 

The regional interstate Algonquin pipeline system transports natural gas from New Jersey and 

southeastern New England to major markets in New England, including Boston, Hartford, and 

Providence [Ref. 12.27]. The Algonquin pipelines transport 2.5 billion cubic feet of gas per 

day to serve approximately fifty percent of the natural gas demand in New England 

(Attachment 6). Algonquin serves as a major artery through the northeast portion of the 

United States, connecting to Spectra’s Texas Eastern Transmission and Maritimes & 

Northeast Pipeline. 

Currently, the Algonquin Pipeline system crosses the Hudson River next to IPEC. Due to the 

significant level of service provided by Algonquin to the region, Spectra has advised that the 

Hudson River crossing is considered a critical site and the throughput of the pipeline facilities 

at this location cannot be interrupted. The Algonquin facilities crossing the IPEC site are 

comprised of two gas pipelines running east to west through the IPEC site on a 65 foot wide 

ROW. At the southwest property boundary, a third pipeline is tied into the two other 

pipelines along with valving and internal inspection facilities for all three pipelines. The 

valve site area is near the Hudson River bank, within the excavation area of the Unit 3 cooling 

tower. The connection piping is visible above ground, as shown in Figure 4.1. The ROW 

expands significantly at the valve site to accommodate the additional piping and equipment. 

The existing Algonquin pipeline ROW is shown by solid white lines in Figure 4.1. The 

proposed location for the Unit 3 cooling tower is shown by a dotted white oval. The 

excavation required for construction of the cooling towers would extend approximately 150 ft 

beyond the dotted oval, to create the 700 ft diameter clearing around the tower and gradual 

slope from the clearing to the existing grade. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

22 

Figure 4.1 Existing Algonquin Gas Transmission Pipeline Right-Of-Way, With 

Proposed Unit 3 Cooling Tower Location Shown by Dotted Line 

4.2 Feasibility of Relocation 

In order to construct the Unit 3 cooling tower configuration shown in Attachment 2, the 

Algonquin pipeline would have to be relocated. Spectra has provided an evaluation of the 

required pipeline relocation and proposed that pipeline be rerouted around the Unit 3 cooling 

tower excavation area, as shown in Attachment 2 ENTGNU011-SK-001 (Attachment 6). The 

lack of available space between the cooling tower excavation area and the Hudson River bank 

would require relocation of the valve site and an extension of the third pipeline. The valve 

site would be relocated along the existing pipeline to the area adjacent to the Broadway 

roadway. An extension of the third pipeline would be installed running parallel to the existing 

pipelines across the IPEC site. At the Unit 3 cooling tower excavation location, all three 

pipelines would be rerouted around the cooling tower to tie into the existing Hudson River 

crossing. The existing 65 ft wide ROW would need to expand to 100 ft wide to accommodate 

the extension of the third pipeline. During blast excavation at the Unit 3 cooling tower 

location, the required blasting offset (50 ft) from the nearest relocated pipeline would prohibit 

blasting within 15 ft of the expanded 100 ft ROW. The Unit 3 cooling tower location has 

moved in a northerly direction from the original location considered in the 2003 Report 

(Attachment 1) to accommodate the expanded ROW and blasting offset proposed by Spectra. 

The revised Unit 3 cooling tower location is shown in this Report (Attachment 2) and is the 

basis for all excavation discussions in this Report (e.g., Sections 5 and 6). 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

23 

The Algonquin Pipeline System is one of the largest interstate pipelines in the United States 

[Ref. 12.23]. As such, it is regulated by the Federal Energy Regulatory Commission (FERC). 

Any relocation of the Algonquin pipeline would require the prior approval of the FERC, a 

process which could take a year or more [Ref. 12.19]. If FERC approval could not be 

obtained, the feasibility of closed-loop cooling for Unit 3 would be in jeopardy, as site real 

estate constraints preclude alternate cooling tower sites. 

4.3 Spectra Schedule and Cost Impacts 

Siting of the Unit 3 cooling tower requires relocation of the Algonquin pipeline facilities, 

which must be approved by FERC. A preliminary timeline and feasibility cost estimate for 

the relocation is provided by Spectra in Attachment 6. 

Spectra’s preliminary timeline, shown in Table 4.1, was developed absent any detailed field 

work, facility design, or agency consultation and without any detailed construction 

coordination concerns. This timeline should therefore be considered a high level overview of 

the time required to relocate the pipeline facilities and may be understated. The relocated 

pipeline facilities would need to be constructed in a staged manner to allow tied-in to existing 

facilities during the months of June through September, when the typical system demands 

may allow for an approximate 7 day outage for each relocated pipeline to be tied-in and 

connected. By scheduling the tie-in during the summer months and in conjunction with any 

other planned system outages, there may be little to no impact to the services of Algonquin’s 

customers (Attachment 6). 

Table 4.1 Spectra’s Preliminary Timeline for Algonquin Pipeline Relocation 

Activity Duration Notes 

Preliminary field work 2 months 

Facility design 4 months 

Permitting 14 months Includes preparations of applications to FERC 

and New York State 

Construction 4 months 

In-Service 21 days 7 day outage to tie-in each pipeline (in sequence) 

must occur between June and September 

Total 24 months Assumes 3 week tie-in occurs during planned 

system outages 

The feasibility cost estimate provided by Spectra for the relocation of the pipeline facilities is 

approximately $13.8 million, with an accuracy level of (-) 25% to (+) 40% (Attachment 6). 

The feasibility estimate considers design, permitting, material, labor, and construction costs. 

Of note, the cost of spoils disposal is not included; therefore, the spoils generated by the 

pipeline relocation are included in considerations of the total spoils that would be generated 

by the conversion of IPEC to closed-loop cooling (Section 6). 

The pipeline would have additional schedule and cost impacts on the conversion project as a 

whole. FERC approval for the pipeline relocation must be obtained before substantial design 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

24 

work for conversion of Unit 3 to closed-loop cooling would be undertaken, and the 

installation of the relocated pipeline would have to be complete before blast excavation could 

begin at the Unit 3 tower location. Each consideration would delay the overall schedule for 

both Units due to the combined outage at the end of the conversion. In addition, due to the 

significant amount and duration of blast removal, Spectra would require field personnel and 

experts to monitor the relocated pipeline facilities throughout the construction period 

(Attachment 6). The cost of pipeline monitoring would be estimated by Spectra after 

evaluation of the blasting plan and construction schedule, and is not currently included. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

25 

5 Blasting 

Conversion of the Stations to closed-loop condenser cooling would require the excavation of 

approximately 2 million cubic yards of soil and inwood marble bedrock. Blast removal would be 

required to excavate large quantities of bedrock at the cooling tower locations and in the piping 

trenches outside of the Riverfront area. The feasibility, cost, and schedule of blast removal have 

been evaluated by Dr. Calvin J. Konya, a nationally recognized blasting consultant. Dr. Konya’s 

report is included as Attachment 7, which updates the original analysis for the 2003 Report 

(Attachment 1). Dr. Konya’s report describes the costs and duration associated with significant 

aspects of blast removal at IPEC, emphasizing the impact of site-specific vibration limits on 

blasting operations. Dr. Konya’s cost estimate for drilling and blasting, excluding removal and 

disposal of spoils, is over $40 million. The drilling and blast removal would be expected to take 

approximately 4 years. 

5.1 Restrictions to Blasting at IPEC 

Blast removal at IPEC would be limited by proximity to Units 2 and 3, the Algonquin 

pipeline, and the Village of Buchanan. The respective vibration limitations imposed by these 

site-specific considerations were reviewed and incorporated into the blasting plan described in 

Attachment 7. 

5.1.1 Onsite Blasting Restrictions 

As discussed in Section 5.2, blasting excavation would be required for a period of 4 years, 

and blasting operations are proposed to occur while both Units are online. In addition, the 

continued operation of the relocated Algonquin pipeline, discussed in Section 4, would be 

required. Therefore, blasting limitations were determined that would allow and ensure the 

continued operation of Unit 2, Unit 3, and the relocated Algonquin pipeline. 

Each Unit is designed to withstand an earthquake of Modified Mercalli Intensity VII, 

which corresponds to a maximum horizontal acceleration of approximately 0.15 g [Ref. 

12.17; Ref. 12.18]. The seismic monitoring equipment, located in the Unit 3 containment 

building, is designed to detect ground motion approaching or exceeding this facility design 

basis. The equipment is triggered by a horizontal acceleration of ≥0.01g to record the 

magnitude, duration, frequency and direction of seismic events. Initiation of the seismic 

monitoring equipment is one of the entry conditions for the seismic event procedure, which 

requires the immediate inspection of various systems, structures, and components at both 

units. In addition, an engineering evaluation of the impact of the seismic event on the 

plant must be completed and the seismic instrumentation must be recalibrated. When a 

horizontal acceleration of ≥0.1 g is detected, an alarm in the Control Room initiates an 

abnormal operating procedure which could lead to shutdown of the reactors. 

The maximum horizontal acceleration of ground motion due to blasting is therefore limited 

to 0.1 g, as measured at the containment structure. The 0.1 g acceleration limit translates 

to a vibration limit of 0.104 inch/sec due to the high frequencies of blasting compared to 

the frequencies of earthquakes. Small diameter blastholes and a tightly-spaced blasthole 

pattern would be used to meet this limit, as discussed in Attachment 7. At the edges of 

excavation closest to the containment buildings, additional vibration control would be 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

26 

implemented by deck loading the blastholes. Deck loading allows several charges in one 

blasthole to be fired independently on millisecond delays, thereby reducing the ground 

vibrations resulting from the blast. 

As discussed in Section 4, the Algonquin pipelines cross the IPEC site to the south of Unit 

3. Spectra, owner and operator of the Algonquin pipelines, has proposed an allowable 

blasting offset of 50 ft as part of a preliminary relocation plan (Attachment 6). Spectra 

Guideline TG-111 specifies a calculation to determine a maximum allowable charge 

weight based on distance from the pipelines. At the edge of the proposed blasting offset, 

50 feet from the relocated pipeline, the maximum allowable charge weight would be 

greater than the charge weight specified in the blasting plan to meet the 0.1g horizontal 

acceleration limit at the containment building. Therefore, the blasting techniques that 

would be used to protect the Unit 3 facilities would satisfy Spectra’s criteria as well, after 

relocation of the pipeline. Spectra would also require field personnel and experts to 

monitor the relocated pipeline facilities throughout the construction period (Attachment 6). 

A thorough analysis of the impact of blasting vibration on specific Unit components and 

the relocated pipelines would be required to finalize blasting procedures. This analysis 

would require testing of individual components to determine appropriate vibration limits. 

Additionally, impact of vibration on construction activities would need to be determined, 

as cooling tower construction for Unit 2 would likely begin before blasting excavation 

ended at the Unit 3 cooling tower site. Each of these blasting considerations would be 

affected by the site-specific ground conditions, which would need to be determined by onsite ground calibration (Attachment 7). 

IPEC personnel may experience noticeable vibration from blasting, e.g., loose objects 

around the site may rattle. There is a slight potential that these effects could also be 

experienced off-site near the Unit 3 tower excavation. The distance from the excavation to 

the nearest residential areas would be approximately 1000 ft; therefore, no noticeable 

blasting effects would be expected in these locations. 

5.1.2 Code of the Village of Buchanan - Quarrying and Blasting 

IPEC is located in the Village of Buchanan, New York. The Village of Buchanan 

designates acceptable hours for blasting operations, and controls the degree of velocity and 

displacement of vibrations during those hours when blasting is authorized [Ref. 12.5]. 

Blasting is not permitted in the incorporated portion of the Village of Buchanan except 

between the hours of 8:00 a.m. and 7:00 p.m., excluding Saturdays, Sundays, and public 

holidays when blasting is not permitted at any time. In compliance with regulated blasting 

industry standards, blasting operations would also only be conducted in daylight; thus, 

blasting operations would end at dusk or 7:00 p.m., whichever is earlier. 

During the hours when blasting is permitted, peak particle velocity and overpressure 

produced by any blast measured at the closest structure or building not owned or used by 

the entity conducting the blast may not exceed 0.75 inch/sec for frequencies less than 40 

Hz or 2.0 inch/sec for frequencies of 40 Hz or more. In addition, air pressure levels 

emanating from such blasts may not exceed 131 dB for a high pass filter of 0.1 Hz, 128 dB 

for a high pass filter of 2 Hz, or 125 dB for a high pass filter of 6 Hz. The blasting plan 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

27 

formulated by Dr. Konya was designed to comply with these Village of Buchanan 

restrictions. 

5.1.3 Code of the Village of Buchanan - Soil Disturbances and 

Excavations 

Entergy’s counsel has advised that construction of the NYSDEC Proposed Project will 

require a soil and excavation permit from the Village of Buchanan. Section 159 of the 

Code states that an application must be submitted and a permit must be obtained from the 

Village Building Inspector prior to any excavation. The Inspector may issue the permit 

only after review and approval by the Village Planning Board. The application must 

demonstrate that the work will not cause, among other things, substantial traffic hazards. 

Also, the application must show that the period of time and the methods for the completion 

of the work are reasonable. Section 159 provides for 2 year excavation permits. Permits 

may also contain restrictions on the excavation, such as a limitation on the hours of 

authorized operations. 

With respect to traffic hazards, and as noted in the discussion of blasting spoils removal in 

Section 6, blasting operations alone would produce between 364 and 518 truck loads per 

day (using 20-cy trucks). As discussed in Section 5.2, blasting and excavation could take 

as long as 4 years. These factors will be considered under Section 159 of the Code. 

Section 159 also requires a certificate of insurance, establishing the extent of liability of 

the applicant or contractor. Inquiries regarding insurance for the NYSDEC Proposed 

Project have received limited response and it may be difficult to obtain coverage for all 

associated risks, especially nuclear incident risks (Attachment 7, Section 3). Thus, 

permitting is not assured. 

5.2 Cost and Schedule Impacts 

The cost and duration of significant aspects of blast removal at IPEC are estimated in Dr. 

Konya’s report (Attachment 7). 

Blast removal duration would be primarily limited by the time necessary to drill the 

blastholes. All blastholes drilled in one day could be prepared, loaded, and fired in 

approximately 15 minutes at the end of the shift. Therefore, the maximum number of drills 

that could be efficiently used would control the project duration. Using typical drilling rates 

for the type of bedrock at IPEC, Dr. Konya estimates that 2078 10-hour days of drilling would 

be required to complete the project. The blasting plan calls for 10 drills to be used, reducing 

the overall project duration to 208 days of drilling. Assuming a typical 85% equipment 

availability, the drill days required would increase to 245 days. Based on actual blasting 

experience in the New York area, Dr. Konya estimates that drilling could only be conducted 

the equivalent of 150 10-hour days per year due to weather shutdowns, equipment delays, 

blasting delays, and shorter drilling and blasting hours in spring and fall due to reduced 

daylight hours. Under typical commercial operating conditions, the blasting would take 

approximately 1.6 years (see Attachment 7). However, at an operating nuclear site, the 

duration would necessarily increase to accommodate the various policies, procedures, and 

work practices dictated by industrial safety, nuclear safety, security, and other relevant site 

programs. Due to these additional considerations particular to the nuclear industry, the 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

28 

duration would be expected to be approximately 2.5 times longer than a comparable 

commercial operation, resulting in an expected duration of approximately 4 years. 

Cost estimates for the significant aspects of blast removal at IPEC are based on the typical 

rates for similarly complex jobs and industry quotations. The overall cost estimate for blast 

excavation for conversion of both Unit 2 and Unit 3 to closed-loop cooling is detailed in 

Table 5.1. Blasting costs are estimated to be over $40 million, not including removal and 

disposal of the spoils (contaminated or clean) generated by blasting. The removal and 

disposal of all spoils generated by the conversion of IPEC to closed-loop cooling are 

discussed in Section 6. 

Table 5.1 Blast Removal Cost Estimate for Conversion of Both Units 

Total Units Rate [/Unit] Cost 

Cooling Towers 1,796,000 yd3 $15 $26,940,000 

Trenches 94,600 yd3 $58 $5,487,000 

Presplitting 61,080 yd2 $85 $5,192,000 

Blasting Consultant 800 days $2000 $1,600,000 

Seismic Monitoring 34 months $26140 $889,000 

Total $40,108,000 

5.3 Blasting Outage Timing 

In order to avoid a prolonged forced construction outage at each Unit, blasting operations 

would occur with both Units online, as discussed in Section 5.1.1. 

Moreover, if blasting operations are able to be coordinated to overlap with scheduled outages, 

the cost of blasting could be marginally reduced. Per Attachment 7, a potential cost savings 

of approximately 5% could be realized during the outage duration by avoiding the need for 

deck loading in the blastholes near Unit 3. However, deck loading would still be required in 

blastholes near the Algonquin pipeline. Blasting during scheduled outages would not impact 

the total number of blastholes required or the presplitting costs. The blasting project duration 

would not be impacted by overlap with scheduled outages; only the cost of blasting in 

proximity of Unit 3 during an outage would be impacted. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

29 

6 Spoils Removal 

Conversion of Unit 2 and Unit 3 to closed-loop cooling would require the excavation of 

approximately 2 million cubic yards of soil and bedrock, nearly all of which is expected to be 

crushed inwood marble. As detailed in Table 6.1, the total estimated disposal volume includes 

excavation for the cooling tower basins and clearings, the circulating water piping trenches, the 

Algonquin pipeline relocation, and miscellaneous requirements of the conversion to closed-loop 

cooling (e.g., parking lot relocation, pump skids, electrical duct banks). The total disposal 

volume is greater than 50% of the total crushed marble sold or used in the U.S. in 2007 [Ref. 

12.34]. Some portion of the excavated material is likely to be radiologically contaminated. As 

such, a sampling program would be developed and implemented prior to excavation, so that 

radiologically contaminated material may be properly managed. The cost and rate of removal 

and disposal of the excavated material would be significant factors in the overall cost and 

duration of the conversion. Radiological contamination concerns may cause delay or increase 

the cost of removal. 

Table 6.1 Estimated Excavation Volumes by Area 

Excavation Area Excavation Volume 

Cooling Tower Basins and Clearings 1,794,300 yd3

Piping Trenches 129,600 yd3

Algonguin Pipeline Relocation 44,600 yd3

Miscellaneous (Parking Relocation, Electrical Equipment, Etc.) 17,900 yd3

Total 1,986,400 yd3

6.1 Blasting Spoils 

Most of the expected 2 million cubic yards of spoils would be produced by blast removal. 

Blast removal would produce rocks of varying size. Approximately 65-77% of the rocks 

produced in the cooling tower site excavation would be larger than 1.5 inch pieces 

(Attachment 7). The blasting in the piping trenches would produce smaller pieces of broken 

rock, with approximately 43-61% of the rocks larger than 1.5 inch pieces. These larger rocks 

would need to be crushed to facilitate transportation offsite. A procession of dump trucks 

would carry the blasted rock from loaders at the blasting site to mobile crushing plants setup 

near the River. One mobile crushing plant would be used at each cooling tower excavation. 

The crushed rock would be dropped directly from the crusher onto a conveyor belt for barge 

loading. 

Each step of the excavation process must be carefully planned and executed to efficiently 

remove the blasted rock. The numbers and capacities of loaders, trucks, screens, crushers, 

conveyers, barges, etc. must be carefully balanced to prevent any individual step in the 

process from becoming a bottleneck. In theory, it may be feasible to remove the blasted rock 

at the maximum rate possible as limited by drilling. If limited only by the drill rate, the 

excavation would produce between 7,265 and 10,350 cubic yards of broken rock per day 

(equivalent to between 364 and 518 truck loads, with 20-cubic yard capacity). In practice, 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

30 

well coordinated efforts would be required to remove, process, and dispose of this expected 

quantity of material. Significant schedule delays could be introduced by any inefficiency in 

the rock removal operation. 

Due to the large scale of the excavation, counsel for Entergy advises that crushing operations 

may be viewed by the Village of Buchanan as a primary use of the IPEC property that is 

prohibited by the Zoning Code, as discussed in Section 8.3.1. 

6.2 Contamination of Spoils 

Historical site assessments and groundwater sampling at IPEC, including that performed by 

GZA, have indicated that groundwater is radiologically contaminated in some areas of the 

site, primarily with strontium-90 and tritium [Ref. 12.14] (Attachment 3). A Long Term 

Groundwater Monitoring Program (LTMP) has been implemented at IPEC to characterize and 

monitor the extent of subsurface contamination. The results of the program have indicated 

relatively stable groundwater contamination plumes and a decreasing trend in radionuclide 

levels [Ref. 12.13]. GZA’s groundwater contamination plume models indicate localized 

contamination near Units 1 and 2 that ultimately discharges to the Hudson River, as shown in 

Figures 1 and 2 of Attachment 3. GZA has advised that all spoils excavated from within the 

plume boundaries would likely be contaminated. Therefore, the volume of contaminated 

spoils that would be generated is expected to be at least 6350 cubic yards. As shown in 

Section 6.5, contamination would increase the cost of spoils disposal. 

Additional sampling and radiological testing would be required to determine the quantities 

and locations of contaminated soil. The sampling program would cover areas that could 

potentially be contaminated, consistent with GZA’s recommendations. The 

blasting/excavation schedule would allow workers sufficient time to monitor blasted rock. 

6.3 On-Site Relocation of Spoils 

A limited portion of the excavation spoils may theoretically be reused or stored onsite. 

However, the expected 2 million cubic yards of excavated spoils would greatly exceed IPEC’s 

storage capacity. As such, most of the material would need to be removed. In addition, the 

only available area onsite for spoils storage would be the eastern hardwood forest habitat to 

the northeast of the Unit 2 cooling tower location. The potential impact on the local terrestrial 

ecology (which includes potential endangered species habit [Ref. 12.11]) would likely 

preclude spoils storage in that area. Due to these considerations and constraints, it has been 

assumed that spoils would not be relocated onsite. 

6.4 Off-Site Relocation of Spoils 

The entire 2 million cubic yards of excavated spoils are assumed to require off-site relocation, 

due to the constraints discussed in Section 6.3. Two separate methods of disposal would be 

required, respectively, for contaminated and clean spoils. 

6.4.1 Radiologically Contaminated Spoils 

Any detection of radiological contamination above a defined minimum detectable 

concentration would require the excavated spoils to be properly disposed of as radioactive 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

31 

waste. Contaminated spoils would be classified as directed by 10 CFR 61.55, based the 

types and quantities of radionuclides present. Class A wastes may have a maximum 

tritium concentration of 40 curies/m3, or a maximum strontium concentration of 0.04 

curies/m3

 [Ref. 12.3]. If both tritium and strontium contamination are present, the 

maximum concentration of both radionuclides is determined by the sum of fractions rule, 

as described in 10 CFR 61.55. The sum of fractions rule significantly reduces the 

maximum concentration allowed of both (or either) radionuclide. 

NRC regulations stipulate that nuclear facilities may only dispose of licensed nuclear 

materials offsite by transfer to an authorized recipient, in this case a licensed disposal 

facility [Ref. 12.1]. Currently, there are three commercial low-level waste (LLW) disposal 

sites in the United States. Only one of these sites would accept waste from Indian Point: 

EnergySolutions Clive Operations (Clive), located in Clive, Utah. Clive is licensed by the 

State of Utah to accept Class A waste, and accepts waste from all regions of the United 

States [Ref. 12.22]. 

In addition to meeting the concentration limits listed in 10 CFR 61.55, Class A waste must 

be packaged according to 10 CFR 61.56. The processing, packaging, and final disposal of 

contaminated spoils would be conducted by specialists in radioactive waste handling and 

processing. In processing, contaminated materials would be identified and separated to 

minimize disposal volumes and reduce the cost of regulated and licensed disposal. 

Contaminated materials would likely be transported by truck to the processing facility. 

6.4.2 Clean Spoils 

Potential options for the off-site disposal of clean spoils include sale as a commodity, use 

as fill material, or artificial reef building projects. Site geologic studies indicate that most 

of the spoils would be inwood marble, a crystalline metamorphic rock “made from” 

limestone with considerable heat and pressure [Ref. 12.14]. Crushed stone is a major basic 

raw material for the construction industry. If clean inwood marble generated by 

excavation could be crushed onsite and sold as a crushed stone commodity, a portion of the 

cost of disposal could be recovered. 

If the clean spoils are not suitable for sale as a crushed stone commodity, another potential 

option for disposal is use as backfill for mine reclamation. In 1975, New York State 

enacted the Mined Land Reclamation law to ensure the environmentally sound, economic 

development of New York's mineral resources and the return of affected land to productive 

use for current and future generations. The law requires each regulated mining operation 

to develop an approved reclamation plan that provides for return to productive use. 

Donation of the crushed rock to artificial reef projects off the coasts of New Jersey and 

New York was considered as another potential method of disposal. The permitting process 

for this method of disposal would likely represent significant additional cost of disposal 

and may introduce schedule delays. Therefore, other options of disposal for the clean 

spoils would likely be preferred. 

For each of the clean spoils disposal options considered, spoils would likely be removed 

from IPEC by barge. Transportation of the spoils by barge would be approximately half as 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

32 

expensive as transportation by trucks.6 In addition, transportation by barge would reduce 

the impact of construction on the surrounding community, including traffic impacts. The 

shoreline locations of several aggregates terminals and existing mines in the region would 

enable direct barge transportation from IPEC. If the final disposal location was inland, 

spoils would likely be removed from IPEC by barge and transferred to trucks at another 

location due to roadway capacity constraints in the vicinity of IPEC. Transportation by rail 

has not been considered due to the lack of a rail spur at IPEC. 

6.5 Cost and Schedule Impacts 

The expected duration of removal and disposal of excavated spoils would be enveloped by the 

schedule for blast removal presented in Section 5.2. The estimated cost of spoils disposal is 

approximately $55,620,000, including radiological contamination testing, limited 

radiologically contaminated spoils removal and disposal, and clean spoils removal. The costs 

of clean spoils disposal would vary greatly depending on the final disposal method. The cost 

of radiological testing and disposal of limited contaminated spoils has been estimated to be 

approximately $9.2 million.7

The removal and transportation of clean spoils from the excavation would cost approximately 

$46,436,000, including labor and equipment (loaders, dump trucks, crushers, conveyers, 

barges, etc.). The final disposal location could significantly affect this estimate. Revenue 

from selling the spoils as a commodity or as backfill would offset a portion of the cost of 

removal, while permitting costs for artificial reef building would increase the total disposal 

cost. 

The estimated cost/revenue of disposal would vary greatly, depending on the chosen clean 

spoils disposal option. Production of crushed marble in 2007 was 7.6 million metric tons 

valued at $71.1 million ($9.36 per metric ton) [Ref. 12.34]. Therefore, the potential revenue 

from selling the excavated spoils as crushed stone could theoretically be over $37 million. 

However, it is likely that the stone would be transported to and sold by a third party, which 

would likely significantly decrease the actual revenues that could be collected. Less revenue 

would be expected if the spoils were used as mine backfill. The costs of permitting would 

include preparation of the application, application fees, and any associated legal fees. 

 

6

 The costs of transportation by barge and by truck were compared using 2009 cost data in MeansCostWorks.com. 

Estimated barge transport cost is based on the expected construction schedule while truck transport cost is based on 

total excavation spoils. Due to this discrepancy in cost rate basis, any change to the planned excavation methods 

that would lengthen construction schedule would also decrease the cost savings of barge transport. 

7

 Cost of radiologically contaminated spoils testing and disposal is based on prior decommissioning work and 

disposal quotes from Toxco Materials Management Center, a radiological disposal company. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

33 

7 Cooling Tower Operation / Plume Emissions 

The operation of the two hybrid cooling towers selected is described in detail in the 2003 Report 

(Attachment 1); however, several specific concerns are discussed in further detail below. 

7.1 Water Consumption 

Conversion of Unit 2 and Unit 3 to closed-loop cooling would significantly reduce the water 

intake currently required by each Unit. However, a continuous supply of water would still be 

withdrawn from the Hudson River for evaporative cooling tower operation, and 75% of the 

water withdrawn would be consumed. In terms of water consumption, closed-loop cooling 

systems have substantially more potential environmental impacts than once-through systems 

[Ref. 12.21]. 

Evaporation and drift from the cooling towers would represent a significant loss of circulating 

water that would have to be replenished. Unlike with the current once-through cooling, the 

water lost through evaporation and drift would not be returned directly to the Hudson River 

and would represent a true loss of River water. Typically, evaporating water leaves a cooling 

tower as a pure vapor, increasing the concentration of total dissolved solids (TDS) in the 

circulating water. Local air quality also contributes to circulating water quality degradation, 

as the air is effectively washed by the water in the tower (i.e., the cascading water in the 

cooling tower acts as a scrubber that removes particulates from the atmosphere and 

concentrates them in the circulating water). To maintain the required water quality for the 

cooling towers sited at IPEC, a portion of the concentrated circulating water, referred to as 

blowdown, would be released to and replaced with water from the Hudson River. Therefore, 

a continuous circulating water supply of 27,440 gpm (Equation 5) would be required to make 

up the total losses from evaporation, drift, and blowdown. Evaporation and drift from the 

towers would amount to 20,594 gpm (Equation 6), or nearly 30 million gallons per day, of 

lost Hudson River water. 

7.1.1 Hudson River Water Consumption 

The brackish water from the Hudson River currently used in the Stations’ circulating water 

systems would also be used for the circulating water in a closed-loop system. Hudson 

River water analysis and flow rate data show that the plant intake is largely fresh water 

during times of relatively high River flow rate, and very brackish when River flows are 

low. As discussed above, evaporation in the cooling tower would increase the 

concentration of dissolved solids in the circulating water, as compared to the River water. 

The number of times the dissolved minerals in the circulating water are concentrated, 

versus the level in the River water, i.e., the cycles of concentration, is an important 

parameter for cooling tower operation. Since the intake water quality at IPEC varies 

dramatically based on Hudson River flow rate, an acceptable number of cycles of 

concentration would be dependent on the current intake water quality. The cooling tower 

circulating water salinity would be maintained at approximately 7200 ppm, or between 

three and five cycles, depending upon the makeup water salinity8

. The higher the salt 

 

8

 Chloride concentration (salinity) data was obtained by the U.S. Geological Service for the Verplanck Station, 

immediately adjacent to IPEC, for the period 1969 to 1975 (Attachment 1). 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

34 

content of the makeup water, the fewer cycles of concentration are necessary to maintain 

7200 ppm dissolved solids in the circulating water. Estimated blowdown and makeup flow 

rates would be based on an annual average Hudson River makeup water salinity of 1800 

ppm and four cycles of concentration, meaning that the concentration of total dissolved 

solids in the circulating water would be four times that of the incoming Hudson River 

water [Ref. 12.29]. To achieve an average of four cycles of concentration in 

implementation, an automated control system would be required to reduce makeup flow 

during periods of good water quality (relatively fresh water) and increase makeup flow 

during periods of poor water quality (brackish water). 

The evaporation and drift flow rates can be calculated using the tower specifications 

provided by the cooling tower vendor, SPX Cooling Technologies (SPX). Evaporation can 

be approximated by multiplying the maximum evaporation percentage, 1.47% for summer 

conditions with the dry section of the cooling towers in operation (Attachment 1), by the 

total water flow rate (gpm). Per the cooling tower vendor, SPX, the total circulating water 

flow rate required by each Unit at IPEC would be 700,000 gpm. Therefore, the maximum 

evaporation flow rate from the cooling towers for each Unit at IPEC is estimated as 

follows: 

E Unit  %Evaporation QUnit  1.47 % 700,000 gpm  10,290 gpm (1) 

The drift rate is calculated by multiplying the drift percentage, 0.001% in this case 

(Attachment 1), by the total water flow rate (gpm): 

DUnit  %Drift QUnit  0.001% 700,000 gpm  7.0 gpm (2) 

The required blowdown to maintain 4 cycles of concentration, C4, is estimated using the 

expected evaporation and drift rates [Ref. 12.28]: 

   

  3,423 gpm 3

10,290 gpm 3 7.0 gpm

1

1

4

Unit 4 Unit

Unit     

    CE C D B (3) 

The makeup flow required by each Unit for cooling tower operation at IPEC is the sum of 

tower water losses due to evaporation, drift, and blowdown: 

MUnit  EUnit  DUnit  BUnit  10,290 gpm  7.0 gpm  3,423 gpm  13,720 gpm (4) 

Figure 7.1 provides a per Unit closed-loop flow cycle, including makeup, evaporation, 

drift, and blowdown flowrates. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

35 

Figure 7.1 IPEC per Unit Closed-Loop Flow Cycle 

The total estimated makeup flow required by IPEC is double the makeup flow required by 

each Unit: 

MTotal  2  MUnit  2 13,720 gpm  27,440 gpm  39.5 MGD (5) 

The total estimated water flow lost from the Hudson River is double the evaporation and 

drift flow from each Unit: 

LTotal  2  LUnit  2    10,290gpm  7.0 gpm  20,594 gpm  29.7 MGD (6) 

As described in Section 2.1.2.1, the closed-loop configuration considered in this Report 

would use service water discharge to provide makeup flow. The maximum required 

makeup flow, based on historical meteorological data and River conditions, would not 

exceed the design capacity of the Stations’ service water systems, i.e., 46,000 gpm at Unit 

2 (including Unit 1 River water flow of 16,000 gpm) and 36,000 gpm at Unit 3 [Ref. 

12.17, 12.18]. IPEC has a maximum design flow capacity of 886,000 gpm for Unit 2 and 

876,000 for Unit 3 [Ref. 12.8]. Therefore, the closed-loop cooling reductions in intake 

flow from total design flow would exceed 94.8% and 95.9% for Units 2 and 3, 

respectively. Based on historic flow data from 2001 to 2008, flow reductions would be 

approximately 98.0% at Unit 2 and 97.8% at Unit 3. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

36 

7.1.2 Recycled Wastewater Consumption 

Consideration has been given to the use of recycled wastewater as an alternative to using 

Hudson River water as makeup water for a closed-loop cooling system at Units 2 and 3. 

The use of recycled wastewater as makeup for cooling towers has been studied at coastal 

power plants in California (Attachment 1). Recycled wastewater can be treated to enable 

cooling tower operation at six cycles of concentration, meaning that the concentration of 

TDS in the circulating water would be six times that of the incoming recycled wastewater 

The estimated evaporation and drift rates would be unaffected by the allowable cycles of 

concentration; therefore, the values would be identical to those calculated in Section 7.1.1: 

 gpm 10 290 Unit E  , gpm DUnit  7.0

The required blowdown to maintain 6 cycles of concentration, C6, is estimated using the 

expected evaporation and drift rates [Ref. 12.28]: 

   

  2,051gpm 5

10,290 gpm 5 7.0 gpm

1

1

6

Unit 6 Unit

Unit     

    CE C D

B (7) 

The makeup flow required per Unit for cooling tower operation at IPEC using recycled 

wastewater would be the sum of tower water losses through evaporation, drift, and 

blowdown: 

M Unit  EUnit  DUnit  BUnit  10,290 gpm  7.0 gpm  2,051gpm  12,348 gpm (8) 

The total makeup flow required by IPEC would double the makeup flow required by each 

Unit: 

 MGD M Total  2  M Unit  2 12,348 gpm  24,696 gpm  35.6 (9) 

The feasibility of the recycled wastewater option depends on the distance between IPEC 

and the nearest wastewater treatment facilities able to provide adequate makeup flow, as 

well as the quality of the recycled wastewater and available treatment options. 

The SPDES permits, discharge flow rates, and distances from IPEC for all SPDESpermitted wastewater treatment plants (WWTPs) located in Westchester County are shown 

in Table 7.1. The distances from IPEC are based on either the facility address or the 

outfall GPS coordinates listed in the SPDES permits. 

Table 7.1 SPDES Water Discharge Permit Flows 

Facility 

(SPDES Permit) Flow 

% Req’d 

Makeup 

Flow 

Driving 

Distance to 

IPEC (approx.) 

Direct 

Distance 

(approx.) 

Buchanan WWTP 

(NY0029971) 

0.5 MGD 

(347.2 gpm) 

1.4% <1 mi. <1 mi. 

Peekskill WWTP 

(NY100803) 

10 MGD 

(6,944.4 gpm) 

28.1% 4 mi. 3 mi. 

Ossining WWTP 

(NY108324) 

7 MGD 

(4,861.1 gpm) 19.7% 10 mi. 9 mi. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

37 

Facility 

(SPDES Permit) Flow 

% Req’d 

Makeup 

Flow 

Driving 

Distance to 

IPEC (approx.) 

Direct 

Distance 

(approx.) 

Yorktown Heights WWTP 

(NY0026743) 

1.5 MGD 

(1,041.7 gpm) 

4.2% 13 mi. 9 mi. 

North Castle WWTP 

(NY109584) 

0.38 MGD 

(263.9 gpm) 

1.1% 25 mi. 16 mi. 

Wild Oaks WWTP 

(NY0065706) 

0.06 MGD 

(41.7 gpm) 

0.2% 29 mi. 16 mi. 

Port Chester WWTP 

(NY0026786) 

6 MGD 

(4,166.7 gpm) 

16.9% 30 mi. 25 mi. 

Oakridge WPCF 

(NY0030767) 

0.08 MGD 

(55.6 gpm) 0.2% 31 mi. 23 mi. 

Yonkers Joint WWTP 

(NY0026689) 

92 MGD 

(63,888.9 gpm) 100% + 31 mi. 25 mi. 

Blind Brook County 

WWTP (NY0026719) 

5 MGD 

(3,472.2 gpm) 

14.0% 32 mi. 26 mi. 

Mamaroneck WWTP 

(NY0026701) 

18 MGD 

(12,500.0 gpm) 50.6% 34 mi. 26 mi. 

New Rochelle WWTP 

(NY0026697) 

13.6 MGD 

(9,444.4 gpm) 38.2% 38 mi. 27 mi. 

As shown in Table 7.1, the SPDES permits for the twelve SPDES-permitted WWTPs 

located in Westchester County indicate that only Yonkers Joint WWTP could provide 

sufficient makeup flow for closed-loop cooling towers. The Yonkers Joint WWTP is 

located approximately 25 miles south-southeast of IPEC along the eastern shore of the 

Hudson River. Pipelines directly connecting IPEC and the Yonkers Joint WWTP would 

have to be routed and installed through or around numerous waterfront commercial, 

residential, and industrial districts, an Amtrak commuter train rail line, and the Briarcliff 

Peekskill Parkway (New York State Route 9A). The considerable costs and numerous 

permits required for such an installation would represent considerable feasibility, cost and 

schedule impacts to the conversion project. 

To avoid long stretches of pipe installation, combining the flow rate of multiple facilities 

closer to IPEC was considered. However, the combined discharge flow rates of all eight 

other WWTFs located less than 25 miles (direct distance) from IPEC would not provide 

sufficient makeup flow for closed-loop cooling towers. 

Assuming recycled wastewater could be transported through 25 miles of heavilydeveloped New York shoreline, recycled wastewater from Yonkers Joint WWTP would 

need to undergo a series of further treatments to enable cooling tower operation at six 

cycles of concentration. This treatment would be similar to that of the 90 MGD recycled 

wastewater treatment plant located at the Palo Verde Nuclear Generating Station [Ref. 

12.26], albeit utilizing approximately 40 percent of the flow rate (35.6 MGD). Using Palo 

Verde’s recycled wastewater treatment plant (including the storage reservoir) for 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

38 

comparison, if recycled wastewater from Yonkers Joint WWTP was utilized, the water 

treatment system required by the Stations would occupy approximately 16 acres. 

Construction of a recycled wastewater treatment plant of this size would further increase 

the costs associated with transporting and processing recycled water for use as makeup 

flow for closed-loop cooling towers. As a result of the considerable unknowns, costs, and 

the numerous permits required, using recycled wastewater from Yonkers Joint WWTP is 

considered infeasible. 

7.2 Cooling Tower Plume Emissions 

Pursuant to the Interim Decision governing this SPDES permit proceeding, air permitting 

expert TRC Environmental Corporation (TRC) evaluated the potential air quality impacts of 

cooling tower plume emissions on the surrounding community, consistent with applicable 

federal, state and local law [Ref. 12.29]. TRC concluded that drift from the cooling towers 

would contain an appreciable concentration of dissolved minerals and additives that form 

particulate matter (PM10 and PM2.5). As such, the cooling towers, individually and 

collectively, would result in particulate matter emissions. TRC determined that these 

emissions would exceed the National Ambient Air Quality Standards for PM10 and PM2.5. 

TRC also examined mitigation measures to reduce particulate emissions, but concluded that 

available mitigation measures would not sufficiently redress air quality concerns in a manner 

consistent with applicable regulatory requirements. TRC concluded that the particulate 

emissions from the cooling towers will cause an adverse air quality impact to the surrounding 

community such that obtaining the required construction and operating air emissions permits 

would not be possible. 

The conclusion reached by TRC for the Stations’ cooling tower particulate emissions mirrors 

the conclusion reached for San Onofre Generating Station (SONGS) [Ref. 12.9]. SONGS is 

located in San Diego County, which like the area surrounding IPEC, is currently designated 

as non-attainment for PM10 and PM2.5. At SONGS, drift impacts due to the operation of 

closed-loop salt water cooling towers would be significant and require a major-source Title V 

air permit from the San Diego County Air Pollution Control District. It was determined that it 

would be unlikely that SONGS could locate and purchase a sufficient number of PM10 

emission credits to cover the emissions from closed-loop salt water cooling towers. If the 

required drift offsets were unavailable, conversion of SONGS to closed-loop cooling would 

be infeasible. 

7.3 Plume Abatement 

As discussed in Section 2, the cooling towers that would be installed at Units 2 and 3 would 

be round hybrid towers designed with noise and plume abatement features, that come at a cost 

to electric output. When cooling towers are operated without abatement, visible water vapor 

plumes can form under certain meteorological conditions. According to TRC [Ref. 12.29], 

these visible plumes normally would be confined to the area immediately over the cooling 

tower and over the IPEC property, although under cool temperatures (typically during the late 

fall, winter, and early spring seasons) with high ambient humidity, elevated visible plumes 

could extend for several hundred to thousands of meters. TRC’s results indicate that, without 

plume abatement (i.e., operation of the cooling towers without using the dry section), a visible 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

39 

plume would occur immediately south and northwest of each cooling tower for 610 daylight 

hours per year on average. 

Plumes could not only result in complaints by local residents and businesses, but also may 

contribute to corrosion and ice formation on nearby components and plume shadowing (which 

could affect the local agriculture by decreasing the amount of ambient sunlight). Therefore, 

in order to avoid visible plumes, the cooling towers at IPEC would be operated with 

continuous plume abatement, with a corresponding loss in electricity output. As discussed in 

Section 3.2.2.2, utilizing the 44 dry section fans (350 HP) at maximum capacity to achieve 

continuous plume abatement would result in a loss of more than 13.5 MWe per Unit (over 

100,000 MW-hrs annually per Unit). 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

40 

8 General Site Considerations 

8.1 Aesthetic Impacts 

The conversion of the Stations to closed-loop cooling would require several new structures to 

be constructed on the site (Section 2), the largest being the hybrid cooling towers. A Visual 

Assessment (VA) was prepared by visual analysis expert Saratoga Associates, Landscape 

Architects, Architects, Engineers and Planners, P.C. (Saratoga). Saratoga evaluated the 

potential visual impact of these structures on the scenic resources of the region consistent with 

applicable state and local law and policy [Ref. 12.25]. Saratoga concluded that, given their 

unprecedented scale and visual impact, construction and operation of cooling towers at IPEC, 

singularly or collectively, cannot be reconciled with applicable aesthetic standards, practice, 

or precedent. Specifically, Saratoga determined that the NYSDEC Proposed Project may be 

incompatible with the NYSDEC Visual Policy in that it impairs scenic resources of statewide 

significance. Furthermore, it is concluded that mitigation techniques would have little effect. 

Figure 8.1 Visual Representation of Cooling Towers at IPEC9

8.2 Archaeological Considerations 

Phase I-A and Phase I-B archeological studies were conducted by ENERCON to assess the 

presence of historic properties in the Area of Potential Effect (APE) from cooling tower 

installation at IPEC [Ref. 12.10]. The Phase I studies identified evidence of both historic and 

pre-historic components in the APE. Reports documenting these findings were submitted to 

 

9

 The visual representation of cooling towers at IPEC provided is for wet-mode operation of the cooling towers. 

This has been provided to illustrate the magnitude of the plume that is created, either visible (wet-mode) or invisible 

(plume abated). It should be noted that even with plume abatement, a visible plume would occur under certain 

meteorological conditions. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

41 

the New York State Historic Preservation Office (NYSHPO). NYSHPO indicated that if a 

decision is made to install cooling towers, the APE should be reassessed, a geomorphological 

assessment should be conducted (if warranted), and a Phase II archaeological site examination 

should be conducted for the historic and prehistoric components identified in the Phase I 

studies. Additional information on the correspondence between ENERCON and NYSHPO is 

documented in Attachment 8. 

In the event of a decision to proceed with the NYSDEC Proposed Project, a Phase II 

investigation would be undertaken to determine if significant archeological deposits are 

present. The duration and cost of a Phase II investigation is unknown at this time. Since no 

additional archaeological cost or schedule delay has been incorporated in this report, both cost 

and schedule are understated. 

8.3 Local Zoning Restrictions 

Entergy’s counsel has advised that the NYSDEC Proposed Project will be subject to certain 

local zoning restrictions. IPEC is located within the M-2 Planned Industrial Zoning District 

of the Village of Buchanan and the Village Zoning Code establishes restrictions on both the 

use of, and dimensions of, structures located on property within this District [Ref. 12.2; Ref. 

12.6]. 

8.3.1 Use Regulations 

Section 211-10 of the Zoning Code authorizes “the peaceful use of atomic energy” as a 

principal use of the IPEC property [Ref. 12.6]. Entergy’s counsel has advised that the 

Village may view the NYSDEC Proposed Project as a separate use, given the blasting, 

crushing, transport and potential sale of clean excavated spoils involved. Section 211 does 

not allow mining, and the Village may prohibit blasting and/or crushing operations. The 

Village does permit certain accessory uses, but these appear to be limited to residential 

uses (i.e., swimming pools, etc) and certain retail sales. Thus, obtaining the requisite 

zoning approvals for the NYSDEC Proposed Project is not assured.

8.3.2 Performance Standards Related to Non-Residential Uses 

Section 211 of the Village Zoning Code also establishes standards for non-residential uses, 

including noise and air pollution standards [Ref. 12.6]. As discussed below, due to these 

standards, obtaining the requisite zoning approvals for the NYSDEC Proposed Project is 

not assured.

8.3.2.1 Noise 

Section 211-23 establishes enforceable standards for noise generating activities [Ref. 

12.6]. The table on the following page provides the allowable decibel levels (as 

measured at the property line), for each frequency range. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

42 

Frequency Ranges Containing 

Standard Octave Bands (cycles 

per second) 

Octave Band Sound-Pressure 

Level (decibels)

20 to 75 65 

75 to 150 55 

150 to 300 50 

300 to 600 45 

600 to 1200 40 

1200 to 2400 40 

Above 2400 35 

Adjustments to the above standards are available if the noise is “not smooth and 

continuous and is not radiated between the hours of 10:00 pm and 7:00 am.” Because the 

cooling towers would be operated continuously and, therefore, would radiate noise 

between 10:00 pm and 7:00 am, these adjustments would not apply.

8.3.2.2 Other Forms of Air Pollution 

Section 211-23 governs “other forms of air pollution” like fly ash, dust, fumes, vapors, 

and gases which can cause damage to health, animals, vegetation or property [Ref. 12.6]. 

As noted in Section 7, TRC determined that operation of the NYSDEC Proposed Project 

will result in emissions of greater than 100 tons per year of PM-10 and PM-2.5 [Ref. 

12.29]. Thus, obtaining the requisite zoning approvals for the NYSDEC Proposed 

Project is not assured.

8.3.3 Dimensional Regulations 

Sections 211-15 and 211-19 provide dimensional regulations for maximum building 

heights in the M-2 Zoning District: (a) 2.5 stories or 35 feet for principal buildings or (b) 

2.0 stories or 25 feet for unattached structures accessory to a nonresidential building. The 

NYSDEC Proposed Project cooling towers are 165 feet tall (Section 2.1). Counsel has 

advised that the NYSDEC Proposed Project, therefore, will require a variance from the 

height limitation. Counsel has further advised that variances must be obtained from the 

Village Board of Appeal, and may take approximately 6 months from application to 

decision. This Village denied a prior attempt to obtain a variance for the construction of 

cooling towers at IPEC; this became the subject of extensive litigation.10 Resolution of 

this litigation took 30 months from the date of the Board’s variance denial to the final 

decision of the Court of Appeal overturning the Board’s decision. 

8.3.4 Site Development Plan Approval 

Section 211-25 requires Planning Board approval of a final site development plan before 

the Village Building Inspector can issue a building permit [Ref. 12.6]. Section 211-26 

indicates that this approval is discretionary and involves consideration of environmental, 

engineering, and aesthetic impacts [Ref. 12.6]. 

 

10 Matter of Consolidated Edison Co. of New York, Inc. v. Hoffman, 43 N.Y.2d 598 (1978). 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

43 

8.3.5 Conclusions 

Entergy’s counsel has advised that construction of the NYSDEC Proposed Project cannot 

proceed as of right. The project is dependent on approval from the Village of Buchanan, 

which is likely to be difficult to obtain based on past precedent. Based on precedent, it is 

assumed that zoning approvals and associated litigation would take approximately 36 

months to resolve. 

8.4 Sound Restrictions 

Entergy’s counsel has advised that the NYSDEC Proposed Project will be subject to certain 

local noise restrictions.

8.4.1 Code of the Village of Buchanan, Chapter 119 

Chapter 119, Section 5 of the Village of Buchanan Code prohibits noise associated with 

construction or demolition between the hours of 7:00 p.m. and 8:00 a.m., if the noise can 

be heard by an individual with normal hearing on public property or beyond the boundaries 

of the property in question [Ref. 12.4]. All other loud or raucous noises likely to annoy or 

disturb people are also prohibited between 11:00 p.m. and 8:00 a.m. As shown in 

Attachment 2, the proposed locations for both NYSDEC Proposed Project cooling towers 

are within approximately 50 to 100 feet of the Hudson River (i.e., public property) and the 

Unit 3 proposed cooling tower is within approximately 50 to 100 feet of the property 

boundary with the Lafarge Corporation. It is, therefore, reasonable to conclude that a 

person of normal hearing located on the Hudson River or near the boundary with the 

Lafarge Corporation could hear noises associated with construction of the NYSDEC 

Proposed Project. As a result, it is likely that construction would be prohibited under 

Chapter 119 of the Buchanan Code between the hours of 7:00 p.m. and 8:00 a.m.11

8.4.2 Noise Impact Evaluation 

The NYSDEC procedure for assessing noise effects is a tiered process that begins with a 

First Level Noise Impact Evaluation. The First Level Noise Impact Evaluation determines 

the maximum amount of sound created at a single point in time by multiple activities of the 

proposed project. Factors evaluated include sound characteristics (frequency and tone), 

receptor locations, and the resulting increase in noise from ambient levels. The Second 

Level Noise Impact Evaluation is subsequently performed and refines the evaluation of the 

noise impact potential by factoring in any additional noise attenuation that will be provided 

by the existing topography and fabricated structures including walls, berms, dense 

vegetation, or buildings. When the First and Second Level Noise Impact Evaluations 

indicate that significant noise effects may occur from a proposed project, a Third Level 

Noise Impact Evaluation is performed that evaluates the options for implementation of 

mitigation measures that avoid or diminish significant noise effects to acceptable levels. 

 

11 An ambient sound monitoring program was conducted in the vicinity of Units 2 and 3 between September 2001 

and January 2002 [Ref. 12.30]. The program concluded that both cooling towers operating continuously will cause 

in increase in noise levels at sensitive receptors of 1 dB(A) or less. Thus, operation of the NYSDEC Proposed 

Project cooling towers – as distinct from construction activities –is not likely to have a recognizable noise impact. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

44 

Mitigation measures may include reducing noise frequency or impulse noise by changing 

equipment, modifying equipment, or using the appropriate mufflers; reducing noise 

duration by limiting the days of operation or hours where construction is allowed; and, 

reducing noise levels by increasing setbacks, erecting sound barriers, or preserving natural 

barriers as possible. 

As stated above, construction activities to convert Units 2 and 3 to closed-loop cooling 

would likely be restricted to between 8:00 a.m. and 7:00 p.m. and would require a noise 

impact evaluation. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

45 

9 Construction and Outage Duration 

As discussed in Section 2, three design alternatives are considered for closed-loop cooling at 

IPEC: (1) retrofit both Units to closed-loop cooling, (2) retrofit only Unit 2 to closed-loop 

cooling, or (3) retrofit only Unit 3 to closed-loop cooling. Conceptual construction and outage 

schedules have been developed for all three alternatives and are provided in Attachment 9. 

Considering the conceptual nature of the current design parameters and the unknown forces 

outside of the project’s direct control, many of the tasks are aggressively optimistic and could be 

severely impacted as work progresses. The initial design and all permitting and licensing 

requirements are assumed to be completed prior to the start of construction. Construction work 

and field engineering would continue in tandem up to and through the recommended outage 

period. 

Several factors could present significant scheduling challenges but were not considered for the 

conceptual construction and outage schedule. These issues, along with the scheduling issues 

addressed in this report, include but are not limited to: 

 Duration of regulatory agency interactions (e.g., federal, state and local 

zoning/permitting/licensing restrictions). 

 Prior relocation of the Algonquin gas pipeline. 

 Uncertainty surrounding the large volume of uncontaminated and radiologically 

contaminated spoils and construction debris disposal. 

 Construction delays due to the possible disturbance of tritiated groundwater pathway. 

 Riverside activities and potential maritime implications. 

 Archaeological concerns delaying construction or requiring resiting of the cooling 

towers. 

 Resource availability (material, equipment, and most specifically craft labor). 

 Impacts of increased plant security and the necessary construction equipment access. 

 Unpredictable weather phenomena (e.g., blasting weather restrictions). 

The above concerns are not all inclusive but represent some of the major challenges to the 

NYSDEC Proposed Project. It would be difficult to determine the exact impacts at this point 

based on probability or severity of the issue involved, but each would tend to increase overall 

cost and schedule, some substantially. 

Subject to the uncertainty detailed above, Attachment 9 provides a schedule of the significant 

construction activities for each of the three design alternatives. It should be noted that to 

accurately reflect the timeframe during which construction activities would begin, the estimated 

local zoning/permitting duration of 36 months, provided by Entergy’s counsel, is included within 

each schedule. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

46 

9.1 Conversion of Unit 2 and Unit 3

As discussed in Section 2.1, the conversion of both Units 2 and 3 to closed-loop cooling 

would require the installation of two round hybrid cooling towers and the associated piping 

and equipment. As shown in Attachment 9, the total length of construction would extend 

approximately 97 months including approximately 42 weeks of continuous forced outage. 

Considering the conceptual nature of the current design parameters and the unknown effects 

of outside forces, the scheduling of many tasks are understated and could be significantly 

impacted, as discussed above. 

9.1.1 Online Construction Schedule 

As discussed in Section 2.1, the cooling towers would be placed to the northeast and 

southwest of the Station’s Containment Buildings, as shown in Attachment 2, Sketch 

ENTGNU011-SK-001. To this extent, construction activities that would not be impactive 

to operation, including excavation of the cooling tower basins and relocation of the 

Algonquin Pipelines, could be conducted with each Unit online. 

Prior to construction of the cooling towers, several general site activities would have to be 

completed at both Units, including access road construction, fence relocation and 

additions, environmental protection measures, barge access construction and security 

modifications. Approximately 13 weeks of general construction activities would be 

required at Unit 2 prior to cooling tower construction. 

Several additional activities would have to be undertaken at Unit 3, including relocation of 

the Algonquin pipelines, an existing parking lot, and the current sewage lift station and the 

demolition of the existing sewage treatment facilities that would result in approximately 

118 weeks of general construction activities prior to the construction of the cooling tower. 

Therefore, construction of the Unit 2 cooling tower would be able to begin first, and, after 

the additional activities were finished at Unit 3, construction of the Unit 3 cooling tower 

could begin. 

Subject to schedule uncertainty, cooling tower construction would be limited by the 

drilling rate of blast operations, as discussed in Section 5, and is estimated to take 

approximately 271 weeks at Unit 2 and 284 weeks at Unit 3 (see Attachment 9). 

Construction of the Unit 3 cooling tower would begin approximately 3 months after the 

start of construction on the Unit 2 cooling tower. As discussed in Section 5, construction 

of hybrid cooling towers would entail significant excavation at IPEC and would require 

approximately 4 years for blasting and rock removal alone. 

9.1.2 Outage Construction Schedule 

In contrast to those activities outlined in Section 9.1.1, due to the proximity of several 

construction activities to nuclear safety-related equipment and the impact on or removal of 

equipment necessary for power generation (e.g., circulating water pumps), certain activities 

would require consecutive extended construction outages. Due to the joint nature of 

several of the construction activities (i.e., demolition of the Riverfront area, construction of 

the pump houses in the existing discharge canal, etc.) the construction outages would be 

conducted concurrently. Approximately 42 weeks of continuous outage for the 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

47 

construction and implementation of closed-loop cooling would be required for each Unit. 

At IPEC, maintenance and refueling outages are scheduled to occur approximately every 

24 months for each Unit and typically last approximately 25 days. The scheduled outages 

are staggered so that both Units are not offline at the same time; therefore it is likely that 

the extended construction outages could be scheduled to coincide with one Unit’s 

scheduled maintenance outage. 

9.2 Conversion of Only Unit 2 

As discussed in Section 2.2, the conversion of Unit 2 to closed-loop cooling would require the 

installation of one round hybrid cooling tower and the associated piping and equipment. As 

shown in Attachment 9, the total length of construction would extend more than 73 months 

including approximately 42 weeks of continuous outage, scheduled to coincide with Unit 2 

maintenance and refueling outage (i.e., a 38 week continuous forced outage). Considering the 

conceptual nature of the current design parameters and the unknown effects of outside forces, 

the scheduling of many tasks represents a best-case scenario and could be significantly 

impacted, as discussed above. 

9.2.1 Online Construction Schedule 

As discussed in Section 2.2, the Unit 2 cooling tower would be placed to the northeast of 

Unit 2, as shown in Attachment 2, Sketch ENTGNU011-SK-002. To this extent, 

construction activities that would not be impactive to operation, including excavation of 

the cooling tower basin, could be conducted with the Unit online. 

Prior to construction of the cooling towers, several general site activities would have to be 

completed including access road construction, fence relocation and additions, and security 

modifications environmental protection. In addition to these activities, barge access 

construction would be required resulting in approximately 13 weeks of general 

construction activities prior to cooling tower construction. 

Subject to schedule uncertainty, cooling tower construction is estimated to take 

approximately 270 weeks (see Attachment 9). As discussed in Attachment 7, construction 

of a hybrid cooling tower at Unit 2 would entail significant excavation and would require 

approximately 4 years for blasting and rock removal alone. 

9.2.2 Outage Construction Schedule 

In contrast to those activities outlined in Section 9.2.1, due to the proximity of several 

construction activities to nuclear safety-related equipment and the impact on or removal of 

equipment necessary for power generation (e.g., circulating water pumps), certain activities 

would require consecutive extended construction outages. Approximately 42 weeks of 

continuous outage for the construction and implementation of closed-loop cooling would 

be required. At IPEC, maintenance and refueling outages are scheduled to occur 

approximately every 24 months and typically last approximately 25 days. It is likely that 

the extended construction outages could be scheduled to coincide with Unit 2’s scheduled 

maintenance outage, resulting in a non-planned forced construction outage of 

approximately 38 weeks. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

48 

9.3 Conversion of Only Unit 3 

As discussed in Section 2.3, the conversion of Unit 3 to closed-loop cooling would require the 

installation of one round hybrid cooling tower and the associated piping and equipment. As 

shown in Attachment 9, the total length of construction would extend approximately 98 

months including approximately 42 weeks of continuous outage, scheduled to coincide with 

Unit 3 maintenance and refueling outage (i.e., a 38 week continuous forced outage). 

Considering the conceptual nature of the current design parameters and the unknown effects 

of outside forces, the scheduling of many tasks represents a best-case scenario and could be 

significantly impacted, as discussed above. 

9.3.1 Online Construction Schedule 

As discussed in Section 2.3, the cooling tower would be placed to the southwest of the 

Unit 3, as shown in Attachment 2, Sketch ENTGNU011-SK-003. To this extent, 

construction activities that would not be impactive to operation, including excavation of 

the cooling tower basin and relocation of the Algonquin Pipelines, could be conducted 

with the Unit online. 

Prior to construction of the cooling towers, several general site activities would have to be 

completed including access road construction, fence relocation and additions, and security 

modifications environmental protection. In addition to these activities, barge access 

construction, relocation of the Algonquin pipelines, an existing parking lot, and the current 

sewage lift station and the demolition of the existing sewage treatment facilities would 

result in approximately 118 weeks of general construction activities prior to the 

construction of the cooling tower. 

Subject to schedule uncertainty, cooling tower construction is estimated to take 

approximately 288 weeks (see Attachment 9). As discussed in Attachment 7, construction 

of a hybrid cooling tower at Unit 3 would entail significant excavation and would require 

approximately 4.2 years for blasting and rock removal alone. 

9.3.2 Outage Construction Schedule 

In contrast to those activities outlined in Section 9.3.1, due to the proximity of several 

construction activities to nuclear safety-related equipment and the impact on or removal of 

equipment necessary for power generation (e.g., circulating water pumps), certain activities 

would require consecutive extended construction outages. Approximately 42 weeks of 

continuous outage for the construction and implementation of closed-loop cooling would 

be required. At IPEC, maintenance and refueling outages are scheduled to occur 

approximately every 24 months and typically last approximately 25 days. Subtracting the 

planned maintenance outage from the construction outage duration, implementation of 

closed-loop cooling at Unit 3 would require a non-planned forced construction outage of 

approximately 38 weeks. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

49 

10 Economic and Power Loss Estimates 

This section estimates the costs or lost electrical generation for the five major aspects of 

converting IPEC Units 2 and 3 to closed-loop cooling: 

 initial capital costs 

 construction outage lost electrical generation 

 lost electrical generation due to new condenser operating parameters 

 lost electrical generation due to parasitic losses 

 operation and maintenance costs, including water treatment costs 

The capital costs of the closed-loop conversion include design, procurement, implementation, 

and startup activities, as detailed in Attachment 10. The duration of the required Unit outages 

described in Section 9 is used to determine the lost electrical generation. 

10.1 Initial Capital Costs 

The initial capital costs to convert the Stations to closed-loop cooling include the cost of 

engineering design; the selection, procurement, and installation of major equipment (i.e., 

cooling towers, pumps, valves, etc.); and the costs of closed-loop construction, including the 

blasting required to excavate the cooling tower areas. Capital cost estimation was done in 

such a way as to minimize the necessary assumptions, and relied instead on well-developed, 

detailed conceptual designs to increase the accuracy of the estimates. The 2003 Report 

(Attachment 1) lists the components and construction activities necessary for closed-loop 

operation, providing a high level of detail to the conceptual design estimation. 

Three estimation techniques were used to determine the initial capital costs: 

(1) Vendor provided budgetary estimates 

Leading industry vendors were contacted for updated quotations on the major 

equipment and material components to allow for as accurate an estimation as 

possible, with the correspondence, reference material, and quotations provided in 

Attachment 9. 

(2) Third-party detailed construction estimates 

Since blasting at each of the cooling tower sites would require a unique 

engineering solution, a nationally recognized consultant was used to determine a 

conceptual design, cost, and schedule for blasting (Attachment 7). 

(3) Computational estimation utilizing national production rates and cost factoring 

Remaining cooling equipment and construction activities were estimated using 

2009 RSMeans cost data software at MeansCostWorks.com. RSMeans is a 

construction cost estimating tool that provides detailed cost estimates for the 

construction industry including labor, piping, concrete, industrial equipment, 

electrical systems, and other heavy construction components. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

50 

The capital cost estimate contained in Attachment 9 combines these resources to produce a 

conceptual cost analysis. The major cost centers were defined and presented in line item 

format in order to provide flexibility in the application of cost. Some of these line items 

would be equally shared by both Units 2 and 3 as several of the required construction 

activities would be common between both Units. These common costs would not simply be 

cut in half and are conservatively assumed to remain if only one Unit were converted to 

closed-loop cooling since there would be additional costs associated with ensuring that the 

operating Unit not being converted would not be adversely impacted by construction at the 

other Unit. The engineering, design, and inspection cost was estimated at 15% of estimates 

which were not quoted for turn-key construction [Ref. 12.31]. 

The anticipated direct capital cost (presented in 2009 US dollars) for the conversion for both 

IPEC Unit 2 and Unit 3 is collectively estimated at a minimum of $1.19 billion without any 

escalation over time. The anticipated direct capital cost for the conversion of only Unit 2 is 

estimated at a minimum of $629 million, and the anticipated direct capital cost for the 

conversion of only Unit 3 is estimated at a minimum of $649 million, without any escalation 

over time. The one-time costs of conversion of both IPEC Units 2 and 3 to closed-loop 

cooling are summarized in Table 11.1. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

51 

Table 10.1 One-Time Costs of Conversion of both Units 2 and 3 to Closed-Loop Cooling 

Capital Costs - Design Estimated Cost 

Design Engineering and Modification Packages $ 25,526,000 

Project Management and Support Labor $ 44,598,000 

Capital Costs - Turn-Key Estimates Estimated Cost 

Blasting $ 40,108,000 

Round Hybrid Cooling Tower (2) $ 410,000,000 

Relocation of Algonquin Pipeline $ 13,800,000 

Subtotal $ 463,908,000 

Capital Costs - Construction Estimated Cost 

Phase I - Online (Pre-Outage) $ 89,495,000 

Phase II - Offline (Outage Required) $ 80,672,000 

Subtotal $ 170,167,000 

Capital Costs - Total Work Scope Estimated Cost 

Subtotal $ 704,199,000 

Corporate Overheads and Work In Progress Cost (30%) $ 211,260,000 

Recommended Minimum Contingency (30%) $ 274,638,000 

Total One-Time Costs $ 1,190,097,000 

10.2 Lost Electrical Generation Due to Construction Outage 

From the construction schedules discussed in Section 9 and detailed in Attachment 9, IPEC 

Units 2 and 3 would require approximately 42 weeks of continuous outage for the 

construction and implementation of closed-loop cooling. Maintenance and refueling outages 

are scheduled to occur approximately every 24 months for each Unit and typically last 

approximately 25 days. The scheduled outages are staggered so that both Units are not offline 

at the same time; therefore it is likely that the extended construction outages could be 

scheduled to coincide with one Unit’s scheduled maintenance outage. Subtracting the 

planned maintenance outage from the construction outage duration, one Unit would require a 

non-planned construction outage of approximately 38 weeks. As Unit 2 and Unit have 

respective net capacities of 1078 MWe and 1080 MWe, a 42 week outage at Unit 2 and a 38 

week outage at Unit 3 would result in approximately 14,502,000 MWhr of lost electrical 

generation. A subsequent report will address forced outage costs specifically. 

As noted in Section 9, the estimated schedule is understated. 

10.3 Lost Electrical Generation Due to New Condenser Operating 

Parameters and Parasitic Losses 

As discussed in Section 3, Unit 2 and Unit 3 are water-dependent, requiring a specific 

quantity of cooling water at a specific design temperature, here consistently cold Hudson 

River water. Below this design temperature, the Stations have the capability of marginally 

increasing electrical production; however, above this design temperature the Stations produce 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

52 

significantly less electricity and could ultimately impact the low pressure turbine procedural 

limits. To analyze the effect closed-loop cooling would have on the Stations’ electrical 

generation, a state-of-the-art PEPSE model for each Unit was used. As discussed in Section 

3, the annual average continuous operational losses for Units 2 and 3 were determined to be 

11.1 MWe and 4.7 MWe, respectively; however, operational power losses would peak during 

warmest conditions when electricity demand is at its highest. Over the historical data 

analyzed (2001-2008), the peak combined operational power loss occurred on June 7th, 2008 

at 2PM, and accounted for a combined operational power loss of 85.4 MWe. 

As discussed in Section 3.2.2.2, the equipment necessary to operate closed-loop cooling at 

Unit 2 and Unit 3 would require significant input electricity, referred to as parasitic losses. 

Closed-loop conversion of the Stations utilizing hybrid cooling towers would require a 

continuous 36.1 MWe per Unit aggregate parasitic loss (72.2 MWe, total). 

The lost electrical generation from both the ongoing operational efficiency losses associated 

operating beyond the original condenser design conditions and the parasitic losses associated 

with the pumps and cooling tower fans is summarized in Table 10.2. These losses require 

replacement sources, as will be addressed in a separate report. 

Table 10.2 Lost Electrical Generation from Conversion of both Units 2 and 3 to Closed-Loop 

Cooling 

Lost Electrical Generation Annual Average Peak*

Operational Efficiency Losses 15.8 MWe 85.4 MWe 

Parasitic Losses** 72.2 MWe 72.2 MWe 

Total Lost Electrical Generation 88.0 MWe 157.6 MWe *

Over the historical data analyzed (2001-2008), the peak combined operational 

power loss occurred on June 7th, 2008 at 2PM. **Parasitic losses are continuous, and thus the annual average and peak electrical 

losses are the same.

10.4 Operations and Maintenance Costs 

As discussed in Section 3.3 of the 2003 Report (Attachment 1), significant operations and 

maintenance (O&M) support for the closed-loop cooling systems would be required. 

Additional O&M costs for the components added due to the conversion to closed-loop cooling 

were estimated by identifying the general tasks for each component, and then based on 

operational experience and input from vendors, quantifying the estimated required man-hours 

and associated costs. 

Although the conversion to closed-loop cooling is complex, significant new/modified plant 

components would be limited to the cooling towers with their fans and booster pumps, and the 

appreciably larger circulating water pumps located in new pump houses. Based on the tasks 

identified in the 2003 Report, annual additional operations support for the closed-loop 

configuration is estimated to be approximately $336,000 for each Unit. Based on vendor 

estimates and historical data, the maintenance costs per Unit were estimated as follows: 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

53 

Annual maintenance cost estimate per Unit (years 1-5) $670,000 

Annual maintenance cost estimate per Unit (years 6-15) $1,340,000 

Annual maintenance cost estimate per Unit (years 16-20) $2,680,000 

As discussed in Section 3.6 of the 2003 Report (Attachment 1), additional chemicals would be 

injected into the makeup circulating water to prevent micro and macro fouling of the main 

condenser and cooling towers. Appreciably increased costs would be associated with the 

increased level of water treatment required for closed-loop cooling. Local conditions could 

greatly affect annual costs, but an annual cost per Unit of approximately $1,005,000 would be 

extremely conservative (i.e., understated). 

To support the equipment necessary for continuous closed-loop operation, significant 

operation and maintenance would be incurred. Below is a summation of these annual costs 

per Unit including labor and material for the hybrid cooling towers and water treatment. 

Years 1 - 5 $2,011,000/year 

Years 6 - 15 $2,681,000/year 

Years 16 - 30 $4,021,000/year 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

54 

11 Conclusions 

Several site-specific conditions exist at IPEC that would challenge the feasibility of the 

NYSDEC Proposed Project. These challenges significantly impact the expected duration and 

cost of the project, which are based on conceptual design absent any practical history of closedloop cooling retrofits at nuclear facilities. 

11.1 Challenges to the NYSDEC Proposed Project 

Challenges to the NYSDEC Proposed Project include, but are not limited to, the following: 

 Air emissions resulting from operation of the cooling towers would exceed the National 

Ambient Air Quality Standards for PM10 and PM2.5. Available mitigation measures 

would not sufficiently redress air quality concerns in a manner consistent with applicable 

regulatory requirements. 

 Due to the size of the structures, construction and operation of cooling towers at IPEC 

may be incompatible with the NYSDEC Visual Policy in that they would impair scenic 

resources of statewide significance. The addition of the cooling towers would have a 

significant negative aesthetic impact on the surrounding area. 

 Documented prehistoric artifacts found in the Unit 3 cooling tower location indicate that 

a site of archeological significance may exist. 

 The construction of cooling towers cannot proceed prior to obtaining a variance from the 

Village of Buchanan Board of Appeal (to allow construction in excess of the maximum 

height allowed) and a site development plan approval from the Village Planning Board 

for the construction of the cooling towers. Village officials are on record in opposition of 

the construction of cooling towers at IPEC and local zoning approvals may be difficult to 

obtain. 

 Algonquin Gas Transmission pipelines currently exist where the Unit 3 tower would be 

constructed and would require relocation. The Algonquin Gas Transmission pipelines 

supply approximately 50% of the natural gas demand in New England and this supply 

cannot be interrupted. A preliminary evaluation suggests that relocation of the pipelines 

may be feasible; however, further evaluation of the pipeline relocation may impact the 

location and/or feasibility of the Unit 3 cooling tower. Any relocation of the Algonquin 

pipeline would require the prior approval of the FERC. 

 Excavation in the Riverfront area would intersect groundwater contamination plumes 

containing tritium and strontium. Construction delays may be introduced due to the 

disturbance of these plumes and the mitigation measures required to properly manage 

radiologically contaminated materials. 

 Conversion of the Stations to closed-loop condenser cooling would require the 

excavation of approximately 2 million cubic yards of soil and inwood marble bedrock. 

Blast removal would be required to excavate large quantities of inwood marble bedrock 

at the cooling tower locations and in the piping trenches outside of the Riverfront area. 

Because a forced outage at both Units would represent a considerable loss in power 

generation, blasting operations are proposed to occur while both Units are online. A 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

55 

preliminary blasting plan is based on IPEC seismic design bases; however, site-specific 

testing and evaluation of blast vibration on individual plant components would be 

required to finalize blasting limitations and methods. 

 A continuous supply of approximately 27,400 gpm of makeup water would be required 

for evaporative cooling tower operation. Unlike the current once-through cooling, the 

water lost through evaporation and drift from the towers would not be returned directly to 

the Hudson River, but instead would represent a true loss of cooling water. This would 

result in a loss of Hudson River water averaging nearly 30 million gallons per day. 

 The topography of the IPEC site and general space constraints limit the potential 

locations for cooling towers. The elevation of the tower basin must be sufficiently low to 

prevent damage to condenser tubes. In addition, the towers require a 700 ft diameter 

excavation for clearance to ensure adequate air flow. The tower locations considered in 

this Report address these concerns, but any required relocation may have significant 

feasibility impacts on the project. 

 Conversion of IPEC to closed-loop cooling would be an unprecedented undertaking that 

would likely encounter unforeseen challenges during design and implementation. Thus, 

assumptions about engineering feasibility, while based on best professional judgment, do 

not have the benefit of either available technology or past efforts at comparable facilities. 

11.2 Duration of the NYSDEC Proposed Project 

The total duration of the NYSDEC Proposed Project is expected to extend almost 13 years. 

An eighteen month design period would precede NYSDEC approval of the project. A delay 

of 36 months is anticipated between NYSDEC approval and the start of construction for 

litigation on project permitting. The estimated length of construction for retrofit of both Units 

2 and 3 would extend 97 months, and include an estimated 42 weeks of continuous forced 

outage and the permitting and construction period for relocation of the Algonquin pipeline. 

The drilling, blasting, and spoils removal would be expected to take approximately 4 years. 

Considering the conceptual nature of the current design parameters, the lack of comparable 

retrofits, and typical unknown conditions that arise in major construction projects, this 

schedule represents a best-case scenario; significantly longer durations than currently 

estimated could result. 

If only Unit 2 were converted to closed-loop cooling, the total length of construction would 

extend more than 73 months including approximately 42 weeks of continuous outage, 

scheduled to coincide with Unit 2 maintenance and refueling outage (i.e., a 38 week 

continuous forced outage). If only Unit 3 were converted to closed-loop cooling, the total 

length of construction would extend more than 98 months including approximately 42 weeks 

of continuous outage, scheduled to coincide with Unit 2 maintenance and refueling outage 

(i.e., a 38 week continuous forced outage). The design and permitting periods would be 

similar to those for conversion of both Units. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

CLOSED-LOOP COOLING WATER CONFIGURATION 

56 

11.3 Cost and Power Loss of the NYSDEC Proposed Project 

The anticipated direct overnight capital cost for the conversion for both IPEC Unit 2 and Unit 

3 is collectively estimated at a minimum of $1.19 billion without any escalation over time. If 

individually converted to closed loop cooling, IPEC Unit 2 and Unit 3 would have estimated 

capital costs of $629 million and $649 million, respectively. 

As Unit 2 and Unit 3 have net capacities of 1078 MWe and 1080 MWe, respectively, a 42-

week outage at both Units 2 and 3, accounting for a coincident maintenance outage at one 

Unit, would result in approximately 14,502,000 MWhr of lost electrical generation. 

In addition to one-time costs and power loss, IPEC would also incur annual costs due to 

conversion to closed-loop cooling. Annual operations and maintenance costs associated with 

closed-loop cooling at IPEC would be more than $4 million for the first five years, with 

increasing costs in the subsequent years due to the need for increased equipment replacement 

and repair. IPEC would also incur ongoing operational and parasitic electrical generation 

losses. If the effect of closed-loop conversion on plant operation is averaged across the entire 

year, the combined operational losses due to decreased condenser efficiency would be 

approximately 15.8 MWe; however, operational power losses would peak during warmest 

conditions when electricity demand is at its highest. Over the historical data analyzed, the 

peak combined operational power loss occurred on June 7th, 2008 at 2PM, and accounted for a 

combined operational power loss of 85.4 MWe. Additional parasitic losses from the 

circulating water pumps and the cooling tower fans and booster pumps would add an 

additional 36.1 MWe per Unit in power generation losses. Summing the operational and 

parasitic losses, Units 2 and 3 combined would experience an average power generation loss 

of 88.0 MWe and peak summer power generation loss of 157.6 MWe. For reference, 157.6 

MWe is enough electricity to satisfy the average power consumption of more than 1.38 

million U.S. households.12

 

12 Calculation based on the 2007 average U.S residential electricity consumption of 936 kWh and the 2007 nationallevel transmission and distribution loss of 6.5% [Ref. 12.32]. 
 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

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57 

12 References 

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12.3 10 CFR Part 61.55. Code of Federal Regulations, Title 10, Energy, Part 61, Licensing 

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12.4 Code of the Village of Buchanan. Chapter 119, Noise. 

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 CONVERSION OF INDIAN POINT UNITS 2 & 3 TO A 

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12.31 United States Department of Energy. Cost Estimating Guide. Publication No. DOE G 

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