Diablo Canyon Power Plant 

Cooling Tower Feasibility Study 

March 2009 

Prepared by: 

Enercon Services Inc. 

401 Roland Way 

Oakland, CA 94621 
i 

DCPP Cooling Tower Feasibility Study 

Table of Contents 

Section Page 

I. Executive Summary 1

 1. Overview 1 

 2. Design and Construction 1 

 3. Nuclear Safety 2 

 4. Environmental Impact and Permitting 2 

 5. Project Schedule and Costs 3 

 

II. Background & Introduction 4 

 

III. Conceptual Design Overview 5 

 1. Location of Cooling Towers 5 

 2. Conceptual Design Summary 9 

 3. Reduction in Electrical Output with Cooling Towers 13 

 

IV. Construction and Engineering Assessment 15 

 1. Relocation and Excavation 15 

 A. Relocation of Existing Facilities 15 

 B. Relocation of ISFSI Haul Road 18 

 C. Site Civil Work 18 

 2. Constructability of Interconnecting Piping 19 

 3. Modifications to Existing Systems and Required New Systems 21 

 A. Condenser Modifications 21 

 B. Service Cooling Water Seawater Supply 22 

 C. Main Circulating Pumps 23 

 D. Circulating Water System Piping 24 

 E. Makeup Water Supply 25 

 F. Chlorination/Dechlorination of Effluent Streams 25 

 4. Electrical System Requirements 26 

 A. Electrical Design 26 

 B. Instrumentation and Controls 27 

V. Nuclear Safety and Licensing 29 

 1. Nuclear Safety System Requirements 29 

 2. NRC Licensing 31 

 3. Security 32 
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DCPP Cooling Tower Feasibility Study 

Table of Contents (cont.) 

VI. Environmental Impacts and Permitting 32 

 1. Air Quality – Plume/Salt Drift 32 

 2. Water Quality – Cooling Tower Blowdown 38 

 3. Adverse Impacts 42 

 4. Permitting 45 

VII. Additional Studies 47 

 1. Special Studies 47 

VIII. Conceptual Schedule 48 

 1. Introduction 48 

 2. Schedule Basis, Calendar, Resources 49 

 3. Pre-Shutdown Construction 50 

 4. Construction During Plant Shutdown 50 

 5. Plant Re-Start and Construction Completion 52 

IX. Cost Estimate Summary 52 

 1. Cost Estimate Overview 52 

 2. Capital Project Costs 53 

 3. Decommissioning Costs 54 

 4. Operation and Maintenance Costs 54 

 5. Replacement Power During Construction 54 

 6. Replacement Power due to Derated Capacity 55 

Acronyms And Abbreviations 58

Tables

Table 1 Issues that Would Threaten the Feasibility of the Project 4 

Table 2 Projected Average Flow to/from Ocean (per Unit) 11 

Table 3 Reduction in Plant Electrical Output 14 

Table 4 Buildings/Facilities that Would Require Relocation 15 

Table 5 Visible Plume Length Frequency Summary – Percent 33 

Table 6 Plume Heights – Centerline Height Percent by Direction 34 

Table 7 Summary of Thermal Plume Analysis 41 

Table 8 Projected Direct Adverse Environmental Impacts of DCPP Retro 44 

Table 9 Required Construction and Operation Permits & Licenses 47

Table 10 Cost Estimate Summary 53 

Table 11 Major Equipment Procurement Cost 56 
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DCPP Cooling Tower Feasibility Study 

Table of Contents (continued) 

Figures

Figure 1 Diablo Canyon Site 6 

Figure 2 Topographic Map of Site 7 

Figure 3 Cooling Tower Location 8 

Figure 4 50,000 Sq. Ft. Warehouse that Would Require Demolition 9 

Figure 5 Cross Section Showing Required Excavation 9 

Figure 6 Proposed Circulating Water Pump Pit (SK-C-8) 10 

Figure 7 Decrease in Generator Output (per Unit) 14 

Figure 8 Displaced Facilities 17 

Figure 9 Revised Site Layout 17 

Figure 10 Existing Circulating Water Conduits 19 

Figure 11 Original Circulating Water Tunnel Excavation & Construction 19 

Figure 12 Existing Underground Utilities West of Turbine Building 20 

Figure 13 Cooling Tower Plume (Looking North) 36 

Figure 14 Cooling Tower Plume (Looking Southeast) 36 

Figure 15 Plumes from Nuclear Power Plant Cooling Towers 37

Figure 16 Hrs/Day that Blowdown Temp Would Exceed Discharge Limit 41 

Figure 17 Conceptual Installation and Plume – Perspective From Ocean 57

Sketches

Circulating Water System Flow Diagram SK-M-1 

Auxiliary Water Systems Flow Diagram SK-M-2 

Auxiliary Water System Arrangement SK-M-3 

Sketch of Blowdown Diffuser Lines SK-M-4 

Cooling Tower Retrofit Electrical Single Line SK-E-1 

Electrical System Oneline for CT Auxiliaries SK-E-2 

Topo Layout of Cooling Towers SK-C-1 

Cooling Tower Profile Existing Ground Elevation SK-C-2 

Cooling Tower Cross Section SK-C-3 

Cooling Tower Basin Layout-1 SK-C-4

Cooling Tower Basin Layout-2 SK-C-5 

Cooling Tower Basin Details SK-C-6 

Pump Pit Plan SK-C-7 

Pump Pit Section SK-C-8 

Pump Pit Walls SK-C-9 

Cooling Tower Schematic Layout SK-C-10 

Cooling Tower Layout & Access Road Relocation SK-C-11 

Cooling Tower Circulating Water Piping Layout SK-C-12 

Cooling Tower Concrete Pipe Cross Section-1 SK-C-13 

Cooling Tower Concrete Pipe Cross Section-2 SK-C-14 

Cooling Tower Concrete Tunnel Layout SK-C-15 

Cooling Tower Concrete Tunnel Layout Sect A-A SK-C-16 
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DCPP Cooling Tower Feasibility Study 

Table of Contents (continued) 

Sketches (continued)

Arrangement of Underground 13.8 kV Conduit Run SK-C-17 

Before Proposed Control Board Changes SK-J-1 

After Proposed Control Board Changes SK-J-2 

DCPP Cooling Tower Control System Conceptual Block Diagram SK-J-3 

Preliminary Triconex I/O Point Count SK-J-4 

Preliminary Bently Nevada I/O Point Count SK-J-5 

Appendices

A-1 Equipment Cost Summary 

A-2 Equipment List 

A-3 Pre-Procurement Design Estimate 

A-4 Design Change Package Estimate 

A-5 Vendor Budget Quotes 

A-6 I&C Detailed Cost Estimate 

A-7 Plume Characteristics of Proposed Cooling Towers at DCPP 

A-8 Civil Quantities Summary 

A-9 Electrical Cable Tray & Conduit Estimate 

A-10 Fuel Consumption Summary 

A-11 Project Cost Estimate 

A-12 Conceptual Schedule 

A-13 Power Plant Systems Effluent Concerns
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March 2009 

DCPP Cooling Tower Feasibility Study 

I. Executive Summary

1. Overview 

In response to the 2008 Tetra Tech Inc. cooling tower feasibility assessment performed 

for the California Ocean Protection Council, PG&E engaged Enercon Services Inc. 

(Enercon) to prepare a more detailed, site-specific assessment of the feasibility of cooling 

towers at the Diablo Canyon site. This assessment builds upon earlier work, including 

the 2003 study by Burns Engineering, and provides a further, more detailed analysis of 

the feasibility of a cooling tower retrofit. There is no precedent for mechanical draft 

cooling towers using saltwater makeup at a nuclear facility, and no precedent for a 

retrofit of the magnitude necessary at Diablo Canyon. Enercon concludes that any 

retrofit at Diablo Canyon is a highly speculative project with likely insurmountable 

permitting obstacles, substantial engineering challenges, significant adverse 

environmental impacts, costs exceeding $4-billion dollars, and uncertainty regarding the 

Power Plant’s post-retrofit operating capacity factors. Further, plant downtime, reduction 

of average net electrical output, and a potential for ongoing reduced capacity factors 

would together cause a significant loss in generation, and would greatly undermine the 

State’s ability to meet its Green House Gas (GHG) emissions reduction goals under 

California Assembly Bill AB 32. 

2. Design and Construction Concerns 

Enercon concludes, as prior reports have found, that only mechanical draft cooling towers 

are remotely feasible at the site. Dry cooling is not feasible due to limited space 

availability, and natural draft towers are not suitable for the site given space and seismic 

concerns. Furthermore, due to limited space, mechanical draft towers could only be nonplume abated. The conceptual layout includes four tower arrays – each 140 feet by 620 

feet, with two rows of ten cells each. Key design and construction issues include: 

• Demolition and relocation of over 170,000 square feet of existing structures, 

parking for 1,000 vehicles, and the Independent Spent Fuel Storage Installation 

(ISFSI) storage cask haul road. 

• Excavation of over 2 million cubic yards of soil and rock. 

• 250,000 diesel truck round trips to haul construction materials and excavation 

spoils. 

• Modification of major existing systems including the main condensers, service 

cooling water heat exchangers, and electrical systems. 

• Extremely difficult tie-in process given existing underground facilities to the west 

and south of the power plant. 
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March 2009 

• Construction of an offshore diffusers system for the discharge of a minimum 72-

million gallons per day of high salinity cooling tower blowdown. 

• Approximately 3-3/4 year construction timeframe, with a minimum of 17 months 

dual-unit downtime. 

• An average of over 3,000 workers, requiring 7.4-million miles of bus trips. 

3. Nuclear Safety Concerns 

Enercon identified several significant issues that will likely require NRC review and 

approval of License Amendment Requests (LARs) in order to ensure acceptable safety 

levels during construction, as well as post retrofit operation. Further analysis of these 

issues is required to make determinations regarding potential conflicts with nuclear safety 

requirements. Key issues include: 

• Increased flood risk to safety-related systems from cooling tower water. 

• Accelerated aging of plant equipment and an increase in possible plant trips due 

to salt deposition. 

• Interruption of the safety-required Auxiliary Saltwater (ASW) system during 

construction. 

• Increased potential loss of offsite power. 

• Rerouting of existing approved ISFSI haul road. 

• Increased risk of interruption to the fire protection system during construction. 

• Security concerns related to the opening of the protected area boundaries during 

construction. 

4. Environmental Impact and Permitting Concerns 

The installation and operation of cooling towers raises significant adverse environmental 

impacts concerns and poses substantial, likely insurmountable, permitting obstacles. Key 

issues identified include: 

• PM10 emissions likely can not be permitted by the San Luis Obispo County Air 

Pollution Control District (APCD). 

• Salt deposition of at least 7,500 tons per year would impact plant equipment, 

adjacent agricultural lands, and terrestrial habitat. 

• The vapor plume from tower operations would be over 2,460 feet high 35% of the 

year. Although low visibility conditions may obscure the plumes, and many 

plumes large enough to be visible are likely to occur at night, meteorological 

conditions conducive to plume visibility are predicted to occur within 1 hour of 

sunrise or sunset on the order of 45 times per year for Avila Beach, and 300 times 

per year for San Luis Obispo. 

• Fossil-fueled replacement power for the minimum 17 month dual-unit downtime 

will result in the emission of roughly 10,000,000-tons of GHGs. Derated capacity 

and additional auxiliary power requirements for cooling tower operations total an 
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March 2009 

average of approximately 55 MW, enough to supply power for approximately 

42,000 California homes. Long term negative impacts on GHG emissions of 

roughly 180,000-tons per year would also result. 

• Construction of a diffuser system in Patton Cove south of the power plant will 

directly disrupt approximately a half-acre of pristine rocky marine habitat. 

• Permits for both construction and operation are required from many government 

agencies including: The California Coastal Commission, State Lands 

Commission, Central Coast Regional Water Quality Control Board, San Luis 

Obispo County (Building and APCD), and the U.S. Army Corps of Engineers. It 

is highly unlikely that all the necessary permits can be obtained. 

5. Project Schedule and Costs 

Enercon’s assessment is that prior order-of-magnitude estimates grossly understate the 

cost of a cooling tower retrofit. A more detailed evaluation of project scope, design and 

engineering, and required construction results in the following regarding costs and 

schedule: 

• The overall duration for construction would be approximately 3-3/4 years. The 

plant shutdown during the construction period would be at least 17 months: 

o Extensive excavation west of the Turbine Building in an area congested 

with both safety related and nonsafety related systems, piping and 

conduits. 

o Significant condenser modifications. 

o Need to assure continued operation of the safety related ASW system to 

provide cooling to the spent fuel pools even during shutdown. 

o Extensive relocation of existing systems and facilities. 

o Massive excavation for cooling tower installation. 

• Total initial project costs are estimated at $4.5 billion (2008 Dollars) and would 

result in an estimated Utility customer rate increase of roughly 10%: 

o Capital costs estimated at $2.7 billion. 

o Cost of replacement power for the minimum 17 month downtime is 

estimated at $1.8 billion. 

o Increased decommissioning costs total $67 million. 

• Additional on-going costs total $39 million annually: 

o Cooling tower operations and related maintenance is estimated at $7.4 

million per year. 

o Replacement Power for derated capacity and cooling tower operations 

totals $31.6 million per year. 

Ongoing costs assume that the plant would be capable of continuing to produce power at 

roughly current levels / capacity factors. If plant operational efficiency decreases, and 

net power production is reduced more than the 55 MW expected, electric rates will likely 

increase even more to cover the purchase of additional replacement power. 
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March 2009 

Table 1: Issues that Would Threaten the Feasibility of the Project 

II. Background and Introduction

Diablo Canyon Power Plant (DCPP) could be subject to a requirement to retrofit the 

existing once-through cooling system to closed-cycle cooling. Ongoing development of 

Federal Clean Water Act Section 316(b) regulations regarding aquatic organism 

Impingement and Entrainment (I&E) and a California Specific Policy for 316(b) rule 

implementation may require all coastal power plants to reduce Marine I&E to levels 

commensurate with a closed-cycle cooling system. Previous conceptual analyses of 

retrofitting DCPP to closed-cycle cooling have been performed by Tetra Tech Inc. 

(2002, 2008) and Burns Engineering (2003). These studies were limited in scope, and do 

not provide detailed analysis regarding existing plant operating system and site issues that 

influence the feasibility of such a project, and the engineering and construction 

challenges that would be posed by implementation of a retrofit. At the request of PG&E, 

Enercon Services developed the following study to expand on the previous studies, and 

further develop the scope, site specific feasibility, projected costs, and a conceptual 

implementation schedule associated with retrofitting DCPP to closed-cycle cooling. 

Enercon developed a more detailed technical conceptual design of the cooling tower 

retrofit than was done in the previous Tetra Tech and Burns studies, including initial 

sizing of the equipment, electrical single line development, earthwork and concrete 

quantity estimation, site/equipment layout considerations, and identification of significant 

technical, permitting, and nuclear licensing obstacles. Cost estimates for procurement of 

the major mechanical and electrical equipment have been obtained from equipment 

suppliers. The Engineering cost estimates for the project are based on years of industry 

Issues that Would Seriously Threaten the Feasibility of a 

DCPP Cooling Tower Retrofit Project 

• Significant Permitting Obstacles. 

• Significant Adverse Environmental Effects. 

• Significant Nuclear Safety/Licensing Obstacles. 

• 17 Month Minimum 2-Unit Plant Shutdown. 

• Severe Shortage of Suitable Land Available For Cooling Towers. 

• Substantial Excavation. 

• Demolition and Relocation of Numerous Facilities. 

• Initial Costs Estimated at 4.5 Billion Dollars. 

• Total Annual Salt Deposition Exceeding 7,500 Tons. 

• Plumes Often Visible From San Luis Obispo and Avila Beach. 

• Greatest Loss in Plant Electric Output (nearly 70 MW per Unit) 

Would Occur at Times of Peak Summer Demand. 
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March 2009 

and Diablo Canyon specific experience. Enercon worked with PG&E and Cannon 

Associates in developing the construction cost estimate and project conceptual schedule. 

Enercon Services, Inc., founded in 1983, is an engineering, environmental, technical and 

management services firm with a wealth of engineering design and project management 

experience in the nuclear power industry, including extensive design change experience 

at Diablo Canyon, as well as specific involvement in studies for retrofitting cooling 

towers at existing power plants. 

Cannon Associates, established in 1976, is a multidisciplinary consulting firm composed 

of civil, structural, mechanical engineers and environmental and land use planners with 

expertise in construction management. Cannon performed civil engineering for the 

Diablo Canyon ISFSI, and coordinated with Granite Construction Inc. for the ISFSI 

construction. 

III. Conceptual Design Overview

1. Location of Cooling Towers 

Perhaps the most challenging aspect of this study has been selection of a suitable location 

for the cooling towers. There is a severe shortage of suitable land available for cooling 

towers at the plant due to its location on a small marine terrace sandwiched between the 

shoreline cliffs and the adjacent steep landslide-prone hillsides. Every potential location 

for the cooling towers results in significant disadvantages or insurmountable obstacles. 

Enercon concludes that mechanical draft cooling towers utilizing seawater as makeup are 

the only potential option. Enercon further concludes that the only viable mechanical draft 

cooling towers would consist of nonplume-abated rectangular bank cooling towers. 

Plume abated cooling towers cannot be installed in any workable configuration at the 

facility due to size/topographic constraints. 

Ideally, from a piping layout viewpoint, it would be desirable to place the Unit 1 cooling 

towers to the northwest of the power block, and the Unit 2 cooling towers to the southeast 

of the power block. However, the area north of the plant is unavailable for several 

reasons including its classification as a sensitive archeological site incorporating an 

extensive Native American (Central Coast Chumash) ancestral burial ground. The 

Diablo Creek and associated established riparian habitat is also located between the 

existing power plant and all northern areas. The creek environment would have to be 

extensively disrupted and developed to accommodate substantial northward construction 

for any plant systems. Additionally, such a location would be undesirable from a salt 

drift viewpoint, since prevailing winds from the northwest would maximize the salt drift 

on the plant and the associated 500 kV and 230 kV transmission lines. 
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March 2009 

Figure 1 – Diablo Canyon Site 

Consideration was given to locating the cooling towers alongside the entrance road south 

of the plant. This has proved unworkable due to the steep terrain of the surrounding hills 

which would require substantial excavation and retaining wall construction. 

Additionally, this area is fairly narrow, and placing the cooling towers too close to the 

ocean is undesirable due to the instability of the soil and the potential for future 

landslides. The great distance of the cooling towers at this location from the power block 

would also mean much greater frictional losses in pumping, driving up power 

requirements. Although locating the cooling towers in this area would have the least 

impact on existing facilities, it has been ruled out due to the reasons cited above. 
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March 2009 

Figure 2 – Topographic Map of Site 

Showing Steep Terrain and Limited Area for Cooling Towers 

Other areas for the cooling towers considered were in the vicinity of Warehouse “B” and 

parking lot #1 as well as to the east of the plant. Again, the steep hillsides to the east and 

unstable soils to the west ruled out these areas. Another disadvantage of a site east of the 

plant would be to increase the salt buildup on the transmission lines and switchyard. 

Additionally, locating the cooling towers at a height significantly higher than the 

elevation of the condensers raises the condenser waterbox operating pressure due to the 

higher static head from the cooling tower risers, as well as increasing the nuclear safety 

related flooding hazard in the turbine building due to the cooling tower supply lines 

draining backwards into the building via a failed waterbox. 

The only possible remaining site for the cooling towers was determined to be in the area 

including the main warehouse, cold machine shop, hazardous materials building, fire 

station, parking lots 6, 7 and 8, engineering office buildings 201 and 202, and a dozen 

smaller buildings (Figure 3). All of these facilities would need to be relocated with great 

impact on the administration and operation of the facility. The Independent Spent Fuel 

Storage Installation (ISFSI) haul road would require rerouting due to the excavation 

requirements for the cooling towers, sending the proposed route through the security 

firing range, necessitating its relocation as well. All four cooling tower arrays would be 

placed at an elevation of approximately 85’ to 90’, requiring a significant excavation 

effort as described elsewhere in this report. It is critical to place the cooling tower basins 

at these elevations in order to minimize the nuclear safety related threat of flooding, as 

well as to reduce overall pumping costs and excessive pressures in the condenser 

waterboxes. 
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March 2009 

As in the previous studies, a natural draft design for the cooling towers was eliminated 

from consideration because of seismic and other concerns. Likewise, circular 

arrangement mechanical draft cooling towers were eliminated from consideration due to 

the lack of sufficient suitable land due to the narrow site layout. 

 

Figure 3 – Cooling Tower Location 

(Displaced Facilities in Red) (SK-C-11 Rev. 0)

Based on the above evaluation, and discussions with a cooling tower supplier as to the 

best size, number, and configuration of cells to fit the available space, the conceptual 

design for each unit consists of two rectilinear arrays of mechanical draft cooling towers, 

20 cells per array, arranged in two rows (side-by-side) of 10 cells each. This 

configuration is called “back-to-back”, having hot water risers coming from the outboard 

side of each cell, and air coming in from the outboard side of each cell. This 

configuration is less desirable than a circular arrangement where cooling air can enter 

from inside and outside the cells, but such a configuration was ruled out at DCPP because 

of the lack of suitable land. The 2-Unit DCPP configuration would thus consist of 4 

rectangular collections of 20 cells, having a footprint of 140’ by 620’ each. For each 

unit, a pump suction pit for the circulating water pumps would be located at the north end 

of the two 20 cell assemblies to take suction from the cooling tower basins (Figure 6). 

The cooling towers proposed are based on an approach of 17oF, with a cost estimate 

provided by Marley, a well known supplier. 
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March 2009 

Figure 4 – 50,000 Sq Ft Warehouse that Would Require Demolition and Relocation 

Figure 5 – Cross Section Showing Required Excavation 

2. Conceptual Design Summary 

Each unit would be retrofitted with two nonplume-abated rectangular configured 

mechanical draft cooling tower arrays. Each cooling tower would be arranged in a backto-back array, 2 cells wide by 10 cells long. 

Each operating unit’s two existing 50% capacity circulating water pumps would be 

replaced with five 25% capacity circulating water pumps (10 total for 2 units) located in a 

new pump pit adjacent to the cooling towers. The use of five 25% capacity circulating 

water pumps (4 plus 1 installed spare) is a typical and commercially prudent and cost 

effective configuration that effectively eliminates downtime due to pump/motor failure or 

maintenance, and eliminates plant load reductions in the event of a single pump trip. The 

pumps would discharge into two new 10 ft square buried conduits carrying the cooling 

water to the west side of the turbine building where they would transition into the 

existing conduits on the way to the main condensers (reference SK-M-1 and SK-C-12). 

Likewise, the cooling flow exiting the condensers would utilize the existing conduits 
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March 2009 

until it reaches the west side of turbine building where it would transition into the 

proposed 10 ft square conduits returning to the cooling towers. 

Figure 6 – Proposed Circulating Water Pump Pit (SK-C-8) 

Three new 50% capacity makeup water pumps per unit (6 total for 2 units) would be 

installed in the intake structure near the present location of the existing circulating water 

pumps and intake coolers (which would be removed should the plant be retrofitted with 

cooling towers). The pumps would discharge into a 48” paralined steel common 

discharge header which would be routed up through one of the to be abandoned concrete 

tunnels going to the turbine building, and on to the two circulating water conduits going 

to the main condensers. 

The present Service Cooling Water (SCW) heat exchangers are cooled by the existing 

once-through circulating water. As discussed below, the warmer cooling water from the 

cooling towers would be too warm, necessitating replacement of the two SCW heat 

exchangers per unit, and many of the components cooled by the SCW system. To avoid 

the need for this replacement and the associated significant additional costs, the SCW 

heat exchangers would be cooled by their own once-through cooling system. Three new 

50% SCW seawater supply pumps per unit, located at the existing intake structure, would 

provide this cooling water for the system heat exchangers. In addition to providing an 

installed spare, the third 50% capacity pump would be operated to supply dilution flow 

for the cooling tower blowdown when needed during times of high wet bulb temperature 

to meet the anticipated facility effluent thermal limit of 20 F° above ambient. 

The present Condensate Cooler in each unit is cooled by a side stream off the oncethrough circulating water, and is used when needed to reduce the main condensate 

temperature and thereby provide additional cooling for the main generator hydrogen 

cooler and stator cooler. The need for this “extra” cooling would increase since the 

condenser backpressure, and thus the condensate temperature, would increase with the 

use of closed loop cooling towers. The warmer water from the cooling towers would be 

insufficient to provide the required cooling. Therefore, a side stream off the proposed 

SCW seawater supply pumps would be used to cool the Condensate Coolers. 
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March 2009 

The present once-through cooling for the safety related ASW system would remain a 

once-through system by necessity, and continue to use existing dedicated intake pumps 

and ocean water supply. Warmer cooling tower circulating water would be insufficient to 

provide the necessary cooling required for the existing plant Component Cooling Water 

(CCW) heat exchangers that are vital equipment in an installed critical nuclear safety 

system. Retrofit of this plant system to function within acceptable Nuclear Operating 

License parameters with closed-cycle cooling is infeasible. 

Flow From Ocean 

Flow (gpm) Description Existing Cooling Towers 

Condenser Cooling (gpm) 860,000 0 

ASW System (gpm) 11,500 11,500 

Service Cooling Water HX (gpm) 4,300 4,300 

Condensate Cooler (gpm) n/a 2,000 

Cooling Tower Makeup n/a 37,800 

Blowdown Dilution (∆T Control) n/a 6,400 * 

Seawater Reverse Osmosis System 500 500 

Total (gpm) 876,300 62,500 

Percent of Existing Flow - 7.1% 

Discharge To Ocean 

Flow (gpm) Description Existing Cooling Towers 

Condenser Cooling (gpm) 860,000 0 

ASW System (gpm) 11,500 11,500 

Service Cooling Water HX (gpm) 4,300 4,300 

Condensate Cooler (gpm) n/a 2,000 

Cooling Tower Blowdown n/a 25,200 

Blowdown Dilution (∆T Control) n/a 6,400 * 

Seawater Reverse Osmosis System 240 240 

Total (gpm) 876,040 49,640 

Percent of Existing Flow - 5.7% 

* When needed for blowdown temperature dilution (~ 25% of the time)

Table 2: Projected Average Flow to/from Ocean (per Unit) 

Both the SCW system supply and cooling tower makeup seawater lines would require 

periodic chemical treatment (concentrated chlorination or chlorine/bromine treatment) to 

control pipeline biofouling. The ASW inlet flow is required to be continuously 

chlorinated to protect the vital function of the system. It would be necessary to 

continuously dechlorinate the effluent of the ASW system, and most likely dechlorinate 
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March 2009 

SCW system effluent during chemical treatment, since the present ability to dilute these 

streams prior to discharge using the high volume main condenser once-through cooling 

water flow would no longer be possible. 

Each unit would require a steady state cooling tower circulating system blowdown flow 

of approximately 25,200 gpm when running at full load. The concentration of the 

circulating water would be 1.5x normal seawater. Thus the blowdown would have a 

concentration of about 52,500 ppm total dissolved solids (TDS) given an average 

seawater concentration of 35,000 ppm TDS. The blowdown stream is toxic to marine life 

due to the higher salt concentration. Therefore, it would either have to be rapidly mixed 

with the ambient seawater as it is introduced into the ocean, or it would have to be treated 

prior to discharge to reduce its TDS concentration back to that of seawater. As discussed 

elsewhere, treatment of this quantity of blowdown is not practical. It has been 

determined that the most practical means of disposal for cooling tower blowdown is 

discharge to an array of diffuser nozzles placed on the ocean floor offshore of the 

facility. The proposed location for a diffuser system is south of the existing power plant 

near Patton Cove. Routing high salinity cooling tower blowdown to the existing plant 

outfall located on the shoreline at Diablo Cove cannot be permitted, nor is it an optimal 

configuration for efficient cooling tower operation. 

The tube side of the main condensers (waterboxes) are designed for 25 psig. Due to the 

height and location of the cooling towers, the new pressure in the waterboxes would be 

on the order of 45 psig, necessitating strengthening or replacement of the waterboxes. In 

addition, the existing rolled tube-to-tubesheet joints in each condenser are presently 

susceptible to saltwater leaks. Leaks into the condensate system can lead to damage of 

the safety related steam generators and/or unplanned plant shutdowns. An increase in 

condenser waterbox pressure would significantly increase leakage and associated 

chloride intrusion into the secondary system. Therefore, the condenser waterbox and 

tubes would be replaced with modular welded tube-to-tubesheet units. 

Mechanical draft cooling towers have considerably more power requirements than the 

existing once-through cooling system. This additional power is primarily for the 

mechanical draft fans required for the tower cells. At 300 horsepower (hp) each, about 

12 MVA per unit are needed at an assumed power factor of 0.88. Other new power 

required for the cooling tower installation would be the makeup water pumps drawing 

about 2,700 kVA per unit. Also, each unit would require a seawater supply to the SCW 

system, requiring another 170 kVA. The new circulating water pumps would have higher 

head requirements than the existing circulating water pumps, resulting in an increase 

power requirement of 2.5 MVA. The various existing auxiliary transformers at Diablo 

Canyon do not have sufficient capacity to provide the additional loads to power the 

cooling tower fans and other auxiliaries. Therefore, a new bay with circuit breakers, 

disconnects, and transformers would be added at the 500 kV switchyard with additional 

transformers and other electrical equipment added downstream to serve the new loads. 

The existing sewage treatment system would most likely need to be upgraded to meet 

more stringent effluent limits. The high volume circulating water system would no 
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March 2009 

longer be available to dilute the treated sewage effluent stream. A new packaged system 

would be sized for 50,000-gpd, and would consist of a flow equalization tank, aeration 

tank, clarifier, clearwell, pressurized multimedia filtration system, anoxic tank for nitrate 

reduction, and a UV light system for disinfection. The effluent could be treated by the 

proposed system to have 10 mg/L of biological oxygen demand (BOD), 10 mg/L of total 

suspended solids (TSS), 5 mg/L of total nitrogen, and 1 mg/L of ammonia. The Seawater 

Reverse Osmosis Unit (SWRO) brine reject and filter backwash effluent would be 

directed to the tower blowdown diffuser system due to high salinity. 

3. Reduction in Electrical Output with Cooling Towers 

Replacing the once-through cooling system using saltwater cooling towers would result 

in a higher backpressure in the main condensers because the cooling water temperature 

entering the condensers would be greater than the present once-through ocean water 

temperature. For purposes of this study, hourly wet bulb temperatures for the years 2003 

through 2007 were taken from the National Weather Service (NWS) Station at the San 

Luis Obispo (SLO) Airport. This data was considered the most accurate of available 

local data, and therefore most appropriate for use in this study. Accurate Diablo Canyon 

site specific data for humidity or wet bulb temperature was not available. The airport 

weather station data gives lower wet bulb temperatures (due to drier inland conditions) 

than would actually be experienced at the Diablo Canyon site. The lower wet bulb values 

cause a reduced estimate of plume size, and a lower prediction of circulating water 

temperatures. Thus the conservative bias introduced by use of SLO rather than site 

specific coastline data results in smaller predicted plumes, and a decrease in the predicted 

loss of plant electrical output. 

The once-through ocean cooling water as measured at the intake structure has an average 

inlet temperature of 53.9oF, with a standard deviation of 2.5oF. The average wet bulb 

temperature is 52.0oF, with a standard deviation of 6.8oF. With the cooling tower 

approach of 17oF, it is seen that with cooling towers in service the circulating water 

entering the condensers would be 69.0oF, on average. When compared with the oncethrough cooling water inlet temperature of 53.9oF, this amounts to an increase of 15.1oF 

on average for condenser inlet cooling water temperatures when using cooling towers. 

The turbine exhaust pressure was determined using standard Heat Exchange Institute 

(HEI) condenser backpressure calculation methodology utilizing the DCPP turbine 

performance test data to determine the associated cleanliness factor. The DCPP Turbine 

(Alstom) Thermal Kit backpressure correction curve was then used to determine the 

effect on generator electrical output. (Note: The original Westinghouse low pressure 

turbine rotors were replaced with Alstom rotors in 2005 & 2006.) 
14 of 59 

March 2009 

Figure 7 – Decrease in Generator Output (per Unit) 

The average yearly loss in generator output due to the proposed cooling tower retrofit 

project (including an optimized condenser) based on a 90% capacity factor (both pre and 

assumed post cooling tower retrofit) would be approximately 204,000 Megawatt Hours 

(MWHr) for Units 1 & 2 combined. When considering the additional loads required for 

the cooling tower fans and pumps, the total decrease in plant electrical output would be 

approximately 451,000 MWHr/yr. The average decrease in generator output with retrofit 

cooling towers and an optimized condenser would be 12.9 MW per unit (25.8 MW for 2-

units). As can be seen in Figure 7, the change in Megawatts would vary from an increase 

of approximately 21 MW per unit to a loss of approximately 69 MW per unit depending 

on the corresponding wet bulb and ocean water temperatures. The gain in MW during 

certain temperature conditions is due to the proposed replacement of the condenser tube 

bundles with new optimized bundles. Unfortunately, as can be seen in Figure 7, the 

greatest loss in generator output would be at the time of peak summer electric demand.

Description MW/Unit MW/2-Units MWHr/year*

Circulating Water Pumps ∆MW 2.2 4.4 36,810 

Makeup Water Pumps 2.4 4.8 40,157 

Cooling Tower Fans 10.0 20.0 167,320 

SCW Seawater Supply Pumps 0.2 0.4 3,346 

Average Lost Generation 12.9 25.8 203,547 

Net Loss in Plant Output 27.7 55.4 451,180 

* 2-Units - Based on a 90% Capacity Factor & 25-Day Refueling Outages. 

Table 3: Reduction in Plant Electrical Output 

Without optimized condensers, the average 2-unit decrease in generator output with 

retrofit cooling towers would be 59.8 MW (versus 25.8 MW with optimized condensers)

with an average yearly generator loss of approximately 471,700 MWHr, and a net loss in 
15 of 59 

March 2009 

plant output of 719,000 MWHr (versus 451,200 MWHr with installation of new 

optimized condensers). 

For purposes of this study and associated cost estimates, it has been assumed that the 

plant capacity factor after the cooling tower installation would be identical to the precooling tower capacity factor (approximately 90% including refueling outages). In 

reality, the capacity factor would likely be reduced due to the increased complexity of a 

saltwater tower cooling system, the corrosive effects on plant equipment due to salt 

deposition from the tower drift, and the potential for tripping of the 500 kV lines due to 

flash-over from excessive salt deposition. 

IV. Construction and Engineering Assessment

1. Relocation and Excavation 

A. Relocation of Existing Facilities 

In order to adequately site the cooling towers, many existing facilities would need to be 

relocated, either onsite to a less convenient location or offsite to the surrounding 

community. These include parking lots 6, 7 and 8, with some 1,000 parking spots, and 

the main warehouse building. The cold machine shop (CMS) is presently located inside 

the security protected area boundary in close proximity to the power block which 

provides significant convenience. With the cold machine shop relocated outside of the 

protected area boundary, this convenience and efficiency would be lost. An even greater 

loss of convenience and efficiency would apply to the main warehouse which would be 

relocated 50% onsite but outside of the protected area and 50% offsite. Facilities such as 

the security firing range, design engineering offices, record storage, etc., would have to 

be relocated entirely offsite adding considerable cost and inconvenience. The following 

table is a list of buildings and facilities that would require relocation and/or demolition.

 Buildings/Facilities that Would Require Relocation and/or Demolition 

Blg # Description Impact Relocate Onsite or 

Offsite? 

Existing 

Sq Ft 

Required Sq Ft 

 Onsite Offsite

115 Main Warehouse Demo & 

Relocate 

Part Onsite & Part 

Offsite 50,000 25,000 25,000 

116 Cold Machine Shop 

(CMS) 

Demo & 

Relocate Onsite 15,000 15,000 0 

506 Radwaste Offices Demo & 

Relocate Onsite 1,000 1,000 0 

508 (near cold machine 

shop) 

Demo & 

Relocate Onsite 1,000 1,000 0 

127 Haz Materials 

Warehouse 

Demo & 

Relocate Onsite 4,000 4,000 0 

201 Design Engineering 

Offices 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 12,000 6,000 6,000 

202 Design Engineering 

Offices 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 4,000 2,000 2,000 

220 Design Engineering 

Offices 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 1,000 500 500 

Buildings/Facilities that Would Require Relocation and/or Demolition (cont.) 
16 of 59 

March 2009 

Blg # Description Impact Relocate Onsite or 

Offsite? 

Existing 

Sq Ft 

Required Sq Ft 

 Onsite Offsite 

248 Outage Human 

Resources 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 1,000 500 500 

250 Project Offices Demo & 

Relocate 

Part Onsite & Part 

Offsite 3,000 1,500 1,500 

252 Project Offices Demo & 

Relocate 

Part Onsite & Part 

Offsite 3,000 1,500 1,500 

217 Restrooms Demo & 

Relocate Onsite 500 500 0 

253 Offices Demo & 

Relocate 

Part Onsite & Part 

Offsite 500 250 250 

260 Security/Records 

Storage 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 2,000 1,000 1,000 

261 Records Storage/ 

Offices 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 2,000 1,000 1,000 

262 Telecom/Project 

Offices 

Demo & 

Relocate 

Part Onsite & Part 

Offsite 2,000 1,000 1,000 

263 Training Facility Demo & 

Relocate 

Part Onsite & Part 

Offsite 2,000 1,000 1,000 

264 Building Services Demo & 

Relocate 

Part Onsite & Part 

Offsite 2,000 1,000 1,000 

251 Fire House Demo & 

Relocate Onsite 3,000 3,000 0 

254 Storage Facility Demo Neither - Eliminate 8,000 0 0 

255 Storage Facility Demo Neither - Eliminate 8,000 0 0 

114 Firing Range Demo & 

Relocate Offsite 3,000 0 3,000 

114A Security Training Demo & 

Relocate Offsite 500 0 500 

114B Security Training Demo & 

Relocate Offsite 500 0 500 

113 Warehouse B Demo Neither - Eliminate 18,000 0 0 

120 Hazardous Waste Demo & 

Relocate Onsite 3,000 3,000 0 

125 Fire Water Tank/ 

Pump House 

Demo & 

Relocate Onsite 2,000 2,000 0 

124 Sewage Treatment 

Plant 

Demo & 

Relocate Onsite 1,000 2,000 - 

165 Biology 

Offices/Career Ctr Demo Neither - Eliminate 2,000 0 0 

160 Biology Laboratory Demo Neither - Eliminate 4,000 0 0 

110 Blast and Paint Facility Demo Neither * 3,000 0 0 

122 GC Fab Shop Demo Neither * 8,000 0 0 

n/a Vehicle Inspection 

Station 

Demo & 

Relocate Onsite 1,000 1,000 0 

n/a Parking Garage I New Onsite - 180,000 - 

n/a Parking Garage II New Onsite - 320,000 - 

Total Square Feet 171,000 574,750 46,250 

* The Blast & Paint Facility and the GC Fab Shop would be incorporated in the new CMS. 

 Table 4: Buildings/Facilities that Would Require Relocation and/or Demolition 
17 of 59 

March 2009 

 

 Figure 8 – Displaced Facilities 

 Figure 9 – Revised Site Layout 
18 of 59 

March 2009 

B. Relocation of ISFSI Haul Road 

Location of the cooling towers would make it necessary to reroute the existing ISFSI haul 

road and re-engineer the subgrade for the anticipated loads. In particular, the new road 

would need to pass to the west of the cooling towers, just east of the Simulator Building 

and the Maintenance Training Building. Beneath the road would be the new circulating 

water concrete tunnels, each having an internal cross section of approximately 10’ x 10’, 

with reinforced concrete walls 3 feet thick. This dimension was selected in order to be 

able to fit all 8 tunnels (4 supply and 4 return) for both units alongside each other as they 

approach the western side of the turbine building. Because of the location of the cooling 

towers with respect to the condensers, the tunnels would have to cross over each other in 

certain areas, meaning deeper excavation. The tunnels would have to be engineered for 

the excessive loads anticipated on the road above them, not only due to the ISFSI casks 

but also due to normal operational/maintenance loads, as well as outage-related loads. 

The revised ISFSI haul road would need to avoid the zones where the potential for 

landslides will exist for 75 years after the installation. This setback requirement 

originates from the California Coastal Commission, and is necessary in order to obtain a 

building permit from San Luis Obispo County. The potential for future landslides exists 

at the location of the existing access road near Warehouse “B” and parking lot #1. 

California Coastal Commission rules do not allow for reinforcement of the littoral area 

around landslides in order to reduce the likelihood of future landslides. These points 

would need to be taken into account when finalizing the new ISFSI haul road. 

C. Civil Site Work 

Siting the cooling towers to the southeast of the turbine building would necessitate 

massive excavation of the hillside to the east of the cooling towers. All four separate 

tower basins would be excavated to a base elevation of 85’ to 90’. The excavations 

would leave slopes of 2 to 1 (tangent = 0.5). Although choosing a higher slope would 

reduce the amount of excavated fill to be removed, the higher slope would be hazardous 

for personnel. On the west side of the cooling towers some excavation and relocation 

work for the access/ISFSI haul road would be necessary (Reference Sketches SK-C-1, 2, 

& 3). 

The volume of excavated soil and rock has been estimated at 2,011,000 bank cubic yards. 

This material would need to be trucked to an offsite disposal facility, requiring roughly 

200,000 truckloads. The total amount of soil and rock includes an estimate that 52% is 

rock, based on review of the geological information in the ISFSI Final Safety Analysis 

Report (FSAR) Update. 
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March 2009 

2. Constructability of Interconnecting Piping 

Figure 10 schematically shows the existing circulating water conduits to the main 

condensers. Connections would have to be made to all the supply and return conduits 

including those coming from the north end of the Unit 1 condensers. Review of detailed 

site drawings clearly shows that the excavations and routing required for these large 

diameter connections would quickly become an extremely complex engineering and 

construction task. 

1-1 NW

1-2 NE

1-1 SW

1-2 SE

2-2 NW 2-2 SW

2-1 NE 2-1 SE Unit 1 Unit 2

ASW

Pumps Circ. Water Pumps

Demusseling Gates

Traveling Screens

Dewatering Gates

Bar Racks

Discharge Structure Intake Structure

Weir

(Blending)

Cutouts

(Crossflow)

Discharge

Throttle Gates

Figure 10 – Existing Circulating Water Conduits 

Figure 11 – Original Circulating Water Tunnel Excavation & Construction 
20 of 59 

March 2009 

The limited area for this intertie in front of the turbine building is extremely congested 

with both safety related and nonsafety related systems, piping, and conduits as shown in 

Figure 12. 

 Figure 12 – Existing Underground Utilities West of Turbine Building 

Constructing the large diameter concrete tunnels with the associated excavation in this 

area would result in the disruption of numerous systems that would have to be relocated 

to accomplish this construction. The safety related ASW system bisects this area, and is 

required to remain in operation even with both units shut down. The difficulty, time, and 

cost associated with these excavations, tie-ins, and system interferences are immense. 

The development of the details of this aspect of the retrofit would likewise be an 

immense task. 

Those utilities which are buried in the vicinity of the proposed tunnel excavations, which 

would require temporary protection and/or relocation during construction and/or final 

relocation upon construction completion, include but are not limited to: 

 

Seawater Reverse Osmosis Lines I&C Conduits & Pull Boxes 

 Telephone Communications Aux Saltwater Vacuum Breaker Lines 

 Microwave Communications Building Roof Drains 

 Security Systems (undefined) Storm Drains 

 Potable Water Piping Yard Fire Loop & Branch Lines 

 Sewage Lines & Septic Tanks Instrument Air & Service Air 

 Electrical Conduits & Pull Boxes Outdoor Lighting 

 Fiber Optic Cables Electrical Grounding Cable 

 12 kV Power Cables Auxiliary Saltwater Lines (ASW) 
21 of 59 

March 2009 

3. Modifications to Existing Systems and Required New Systems 

A. Condenser Modifications 

The present condenser has a history of tube leaks which would be made worse by 

significantly increasing the waterbox pressures. The present condensers have 2 to 3% of 

their tubes plugged due to leakage. Increased tube leaks would have an adverse impact 

on the operation of the condensate polishers and potentially an adverse impact on 

transient feedwater and main steam chemistry. Secondary side water chemistry is an 

important aspect of nuclear safety due to potential degradation of steam generators and 

main turbines (missile generation) and potential plant trips. Plant trips due to chemistry 

excursions unnecessarily exercise plant safety systems. Transient departures from water 

and steam chemistry limits would, as a minimum, impact the steam generator and main 

turbine warranties. 

The tube side of the existing main condensers (tubes, waterboxes, and transition pieces) 

is designed for 25 psig. Due to the height and location of the cooling towers, the new 

pressure in the waterbox would be on the order of 45 psig, necessitating strengthening or 

replacement of the waterbox. Additionally, as noted previously in this report, the rolled 

tube-to-tubesheet joints in the installed condensers are currently susceptible to saltwater 

leaks into the condensate system (which can lead to damage of the safety related steam 

generators and/or unplanned unit shutdowns). The increase in condenser waterbox 

pressure would increase leakage. Because of these current design limitations and the 

high probability of significantly increased chloride salts intrusion associated with 

elevated system pressures, the condenser waterboxes and tubes would be replaced by 

necessity with modular welded tube-to tubesheet units. The transitions from the buried 

conduits to the waterboxes would also be upgraded to withstand the increase in pressure. 

In order to optimize the performance of the new bundles and thereby minimize the lost 

generation due to hotter inlet cooling water, the proposed tube bundles would be 

composed of 3⁄4” diameter titanium tubes (compared to the present 1” diameter tubes) 

resulting in increased total tube surface area. 

Installation of the new condenser tube bundles would be a major undertaking. In order to 

provide access for the new bundles, existing equipment and large structural members 

would have to be removed and then reinstalled. The lower end of the large transition 

pieces from the waterboxes to the underground conduits are imbedded in the turbine 

building floor concrete, necessitating concrete excavation and replacement. 
22 of 59 

March 2009 

B. Service Cooling Water Seawater Supply 

Inside the turbine building the circulating water presently cools not only the main 

condensers but also the SCW heat exchangers and the condensate cooler for the main 

generator hydrogen coolers (to maintain generator gas temperature within limits). 

The increase of cooling water temperature to 17°F above the highest wet bulb 

temperatures (as well as the increase in pressure) would necessitate replacement of both 

the SCW heat exchangers and the condensate cooler for each unit, and many of the 

components cooled by the SCW system. 

The SCW system removes heat from various secondary system components via a closed 

loop cooling cycle and rejects the heat to the main circulating water system. The closed 

loop SCW system presently runs with a typical cold end temperature on the order of 79°F 

(e.g. 54°F on average seawater inlet flow cools the service cooling water to 79°F). Even 

if the existing heat exchangers were replaced with much larger heat exchangers, it would 

not be possible to cool the SCW to 79°F using the warmer circulating water from the 

cooling towers during periods of highest wet bulb temperature. 

The heat loads cooled by the SCW system include: 

• Main Feed Pumps Turbine Lube Oil Coolers 

• Condensate Booster Pumps Lube Oil Coolers 

• Generator Exciter 

• Fuse Wheel 

• Generator Seal Oil Coolers 

• Iso-Phase Bus Coolers 

• Main Turbine Reservoir Lube Oil Coolers 

• Post LOCA Sampling System Room Air Conditioning and Sample Panel Chiller 

• Plant Air Compressors 05 and 06 (via the SCW Booster Pumps) 

• Reciprocating Air Compressor Jacket Coolers and Aftercoolers 

• Air System Air Dryers 

• TSC Air Conditioning Units 

• Personnel Access Control Room Air Conditioning Unit 

• Operations Ready Room Air Conditioning Unit 

• Condenser Vacuum Pump Seal Water Heat Exchanger 

• Electro-Hydraulic Control Coolers 

• Feedwater Sample Cooler 72 

• #2 Heater Drain Pump Lube Oil Coolers and Sample Cooler 

• Secondary Process Control Room Isothermal Bath Water Chiller 

In addition to replacement of the SCW heat exchangers themselves, many of the above 

components cooled by the system would require modification or replacement due to the 

higher SCW closed loop circulating cooling water temperatures. To avoid the need for 

these extensive plant equipment upgrades, the existing SCW heat exchangers would be 

cooled by their own once-through cooling system. Therefore, for each unit, three new 
23 of 59 

March 2009 

50% SCW seawater supply pumps (6 total) sized at 3,150 gpm at 86’ total differential 

head (TDH) would be provided. They would draw water from the intake structure and 

the cooling flow would be routed in new 20” paralined steel pipes up to the turbine 

building. The new 20” lines must be routed through an already congested area 

surrounding the main condensers to the SCW heat exchangers located on the east side of 

the turbine building. A branch to the condensate coolers would be provided even though 

the equipment is infrequently used at present for either unit. This routing would replace 

routing which presently consists of short runs from near the main condenser intake lines 

embedded in concrete below the 85’ (ground) level. The new piping would not be 

embedded in the concrete, and would therefore invariably have a negative impact on 

operating and maintenance activities in the vicinity. 

To minimize biofouling, it would be necessary to chlorinate the SCW seawater supply 

lines. The sodium hypochlorite injection system used for the existing main circulating 

water system would be used for this purpose. 

C. Main Circulating Water Pumps 

The proposed cooling systems new main circulating water pumps would be 25% capacity 

each, with one installed spare per unit. They would be rated at 215,000 gpm at 110’ 

TDH. The motor size would be 7,600 hp and would operate at 327 rpm. The five pumps 

would be vertical turbine configuration, arranged in a row, taking suction from the pump 

pit which is adjacent to the cooling towers. The pumps would discharge into a common 

8’ diameter paralined steel circular cross section manifold with valves on either side of 

the middle pump’s tee into the manifold. This would allow any 4 of the 5 pumps to be 

operated. At either end of the manifold, a transition is made into a 10’ by 10’ square 

cross section reinforced concrete tunnel. These two tunnels are directed side-by-side and 

transition into the existing 11’-9” square concrete tunnels which lead to each unit’s main 

condensers. With this configuration, similar to the existing configuration, the plant may 

be operated at 50% capacity while one side of each main condenser is taken out of 

service. Unlike the present configuration without a spare, the spare pump would be able 

to serve either supply tunnel in the event of another pump’s failure. 

Each pump’s capacity of 215,000 gpm would mean a sudden reduction of flow whenever 

that pump is taken out of service. This could give rise to pressure fluctuations, known as 

“water hammer”, with possible destructive results. Thus, studies of the effects of water 

hammer would be recommended, in order to mitigate its detrimental effects. Another 

characteristic of the closed cooling tower loop being considered is the fact that upon 

shutdown of the circulating water pumps, some water would flow backward from the 

high points in the condenser waterboxes (elevation of ~104’) and the cooling tower hot 

side distribution piping (elevation ~125’) into the cooling tower basin / pump pit. The 

basin and pit combined capacity would be sized to accommodate this overflow, which 

would be routed to the ocean through the weirs discharging to the system blowdown 

lines. 
24 of 59 

March 2009 

D. Circulating Water System Piping 

Piping conforming to Piping Specification “G” would be utilized. This is steel pipe with 

an internal coating called “paralining”. It has provided excellent service for existing 

Diablo Canyon seawater applications such as the ASW system, and is suitable for the 

proposed circulating water system. Concrete coated steel pipe is inferior because of 

minute cracks in the concrete lining allowing chloride migration to the underlying steel 

with subsequent destructive corrosion. 

Although Specification “G” includes pipe up to a maximum diameter of 24”, the 

company that provided the pipe in the past, Barber-Webb, has indicated that pipe up to 8’ 

diameter can be paralined. The coating must be applied under controlled conditions in 

the factory. This means it would need to be flanged as opposed to welded in the field 

since the coating cannot be applied reliably in the field. Sections up to 40’ in length can 

be shipped to the jobsite. Paralined pipe would be used for the makeup water supply, 

cooling tower blowdown, and the SCW seawater supply. Additionally, the discharge of 

each of the circulating water pumps would be a paralined 78” diameter steel pipe 

(Reference Sketches SK-C-12 to 16). The common discharge line that all five pumps 

connect to would be an 8’ paralined pipe. 

For the long sections of buried circulating water conduit to and from the cooling towers, 

concrete-walled tunnels are specified. Conveying 50% of the total flow, they would be a 

10’ by 10’ square cross section with 12” 45° fillets at the corners. The walls would be 

about 3’ thick with steel reinforcement. This configuration and material of construction 

is consistent with the existing tunnels, although the existing tunnels are larger, with a 

cross section of 11’-9”. The new tunnels would have a velocity of 9.8 feet per second 

(fps) vs. 7.0 fps for the existing tunnels, but the increased pressure drop is tolerable. 

Having the smaller cross section allows for a more compact arrangement, especially to 

the west of the turbine building where all 8 tunnels (4 supply and 4 return) would be 

buried side-by-side. The new tunnels would be built in place in excavations prepared for 

them. In some areas to the west of the turbine building and to the west of the cooling 

towers, the tunnels would need to cross underneath each other, requiring extra deep 

trenching. This configuration cannot be avoided since the proposed cooling towers for 

both units are on the south side of the plant. 

In the area to the west of the turbine building the new tunnels would transition into the 

existing tunnels. At this interface, a barricade would be constructed in the old tunnels to 

isolate them from the empty sections coming from the ocean intake structure and going to 

the discharge structure. These empty tunnels coming up the hill from the intake structure, 

specifically lines 1-1 and 2-1, would have the 48” makeup water lines and the 20” SCW 

system lines routed inside them up to an area near the transition point where they would 

be routed out of the tunnel on to their respective destinations. 
25 of 59 

March 2009 

E. Makeup Water Supply 

New makeup water pumps would be installed in the intake structure near the removed 

circulating water pumps. Each unit would be furnished with three, 50% capacity makeup 

water pumps sized at 22,500 gpm at 216’ TDH. With two pumps running, a maximum 

makeup flow of 45,000 gpm can be delivered, providing a margin over the steady-state 

makeup requirement of 37,800 gpm. The individual pumps would discharge into a 36” 

paralined steel pipe. The common discharge header for each unit would be a 48” 

paralined steel pipe. This pipe would be routed through one of the existing concrete 

tunnels going to the turbine building that would be abandoned if the plant were retrofit 

with cooling towers. The 48” makeup water line would be taken through the tunnel wall 

near the junction point where the new 10 ft square concrete tunnels coming from the 

cooling towers joined the existing tunnels. The makeup water line for each unit would 

then branch into two 36” paralined steel pipes each going to one of the two main 

circulating water tunnels leading to the main condensers. 

F. Chlorination and Dechlorination of Effluent Streams 

As mentioned elsewhere in this report, both the service cooling water supply lines and the 

makeup water supply lines would be chlorinated to control pipeline marine biofouling. 

The ASW stream is also continuously chlorinated. It would be necessary to dechlorinate 

both the ASW and SCW systems downstream of the heat exchangers since the ability to 

dilute with main condenser flow would no longer be possible. 

The existing site dechlorination system utilizes aqueous sodium bisulfite injected into the 

condenser discharges. This system is currently installed to service only the main 

condensers periodically, and would require significant modification to service other 

effluent streams directly, as well as operate on a continuous basis. For a combined flow 

of 16,000 gpm per unit (ASW and the SCW seawater supply) approximately 61 gallons 

of commercial bulk sodium bisulfite would be required each day to adequately 

dechlorinate. This would result in additional annual chemical supply costs of $150,000. 

The estimate is based on an initial residual chlorine level target of 1 part per million 

(ppm) at system heat exchanger inlets. 

The blowdown stream could contain residual chlorine, however it would be expected in 

very low concentrations under most circumstances. Chlorine would be introduced into 

the main circulating water system under normal operating conditions by the makeup 

water supply. However, the treated influent would represent only a small percentage of 

the systems total circulating volume at any given time. System chemical demand, 

including operation of the cooling towers that would result in extensive exposure of the 

circulating water to the atmosphere, would likely cause rapid reduction of residual 

biofouling treatment chemicals. It is not anticipated that routine injection of additional 

sodium hypochlorite into the cooling tower circulating water would be required because 

the concentration of salts in the system would be toxic to most common forms of aquatic 

life. 
26 of 59 

March 2009 

If excessive organic microfouling of main condenser tube surfaces did occur under 

certain conditions, periodic oxidant treatment of the cooling tower circulating system 

may be required. In that event, the blowdown stream could be temporarily isolated until 

residual chlorine levels reduced below discharge limitations, the entire circulating system 

could be dechlorinated, or the blowdown flow could be directly dechlorinated. Main 

condenser circulating system effluents should not otherwise require dechlorination. 

4. Electrical System Requirements 

 

A. Electrical Design Features 

Mechanical draft cooling towers have considerably more power requirements than the 

existing once-through cooling system. This additional parasitic power is primarily for the 

mechanical draft fans required for the cells. At 300 hp each, about 12 MVA per unit are 

needed at an assumed power factor of 0.88. Other new power required for the cooling 

tower installation would be the makeup water pumps drawing about 2,700 kVA per unit. 

Also, each unit would require a seawater supply to the service cooling water system, 

requiring another 170 kVA. 

The new circulating water pumps would replace the existing circulating water pumps 

which would be abandoned and removed from the intake structure. The new circulating 

water power requirements are roughly equivalent to the existing requirements but would 

not be fed from the existing 12 kV buses. Rather, new 13.8 kV power would be brought 

down from the 500 kV switchyard. 

The various existing auxiliary transformers at Diablo Canyon do not have nearly enough 

margin to provide the additional loads to power the cooling tower fans and other 

auxiliaries. The most practical and cost effective way to provide the new power 

requirements has been determined to take power from the outgoing 500 kV transmission 

lines, one 500 kV line source for Unit 1, the other for Unit 2. A new bay at the 500 kV 

switchyard would be required to locate each unit’s cooling tower transformer (Reference 

Sketch SK-E-1). The power sent to these transformers would need to be metered in order 

to make corrections to the power sent out. The voltage would be first reduced from 500 

kV to 13.8 kV, with the outgoing 13.8 kV conductors routed down to the cooling tower 

locations (Reference Sketch SK-C-17). A voltage level of 13.8 kV is selected rather than 

12 kV because 13.8 kV is a more standardized high voltage level used in industry. The 

500 kV/13.8 kV transformers would be rated at 64 MVA with a power factor of 0.88. At 

the cooling tower area, the 13.8 kV conductors would be routed to the new circulating 

water pumps, rated at about 7,600 hp each, five per unit. The other 13.8 kV conductors 

would be routed to three transformers per unit, each having a rating of 13.8 kV/4 kV, 5.4 

MVA capacity. Individual 4 kV buses would be routed from each of the three 

transformers into an adjoining electrical equipment building where the 4 kV breakers for 

the 40 cooling tower fan motors would be located. Each unit’s cooling tower electrical 

building would be approximately 16’W x 160’L x 12’ H, constructed of protected coating 

steel, and set atop a concrete foundation. 
27 of 59 

March 2009 

The new service cooling water supply pumps and makeup water pumps and their 

transformers and switchgear would be located in the existing intake structure, placed 

immediately on the upstream (intake bay) side of where the existing circulating water 

pumps now reside. Power for the makeup water pumps would be 4 kV, from new 

transformers, one per unit, rated at 12 kV/4 kV with a capacity of 9 MVA each. The 

service cooling water seawater supply pump motors, at 100 hp nameplate each, would be 

stepped down to 440V, requiring additional small transformers. The 12 kV input power 

for the 12 kV/4 kV transformers would come from the existing 12 kV feeds to the 

abandoned circulating water pumps (Reference Sketch SK-E-2). 

B. Instrumentation and Controls 

The existing high voltage electrical bus and circulating water system controls are via hard 

wired relay logic. The operator interfaces for these systems consist of hardwired 

switches, indicators, and annunciator windows on vertical boards VB-5 and VB-4, 

respectively, in the main control room. There is insufficient space in the main control 

room to provide similar hardwired operator interfaces for the additional high voltage 

buses and circulating water system controls. Modern control systems reliably utilize 

touch screen operator interfaces and digital controls. Therefore this approach would be 

used. 

Refer to Sketch SK-J-3 for a conceptual block diagram of the proposed control system 

and operator interface. The proposed control system for the new high voltage buses and 

the circulating water system would be the Triconex Tricon digital control system. This 

highly reliable, triple redundant platform already provides the main turbine controls and 

feed water system controls at DCPP. It has been approved for safety related applications 

by the NRC, and DCPP intends to use it for safety related control and protective systems 

in future upgrade projects (Note: Electrical protective functions such as over-current 

protection would be performed by equipment other than the Triconex). The Triconex 

control hardware (one main chassis, three expansion chassis, and associated field 

termination panels per unit) would be located in the electrical room at the new cooling 

tower location. A total of four Triconex cabinets per unit would be anticipated in this 

location. There would also be a remote input/output (I/O) expansion chassis per unit and 

associated field termination panels located in the intake structure. A total of two 

Triconex cabinets per unit are anticipated in this location. Reference Sketch SK-J-4 for a 

preliminary Triconex I/O list. 

Machinery vibration monitoring would be provided by four Bently Nevada racks per unit 

in the cooling tower electrical room and three racks per unit in the intake structure. Three 

Bently Nevada cabinets are expected to be required in the former location and two in the 

latter per unit. Data would be transmitted to the Triconex control system via data links. 

Reference Sketch SK-J-5 for a preliminary Bently Nevada I/O list. 

Chemistry monitoring and injection controls would be required for the new bisulfite 

injection system. Control would be through the Triconex. 
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Interface equipment would be required for a connection to the Cal ISO for monitoring 

power usage of the new equipment. 

The main operator interface would consist of touch screen human machine interfaces 

(HMIs) in the main control room. Sketches SK-J-1 and 2 show that two HMIs would be 

installed on the bench board section of VB-4. A panel in the cooling tower electrical 

room would have two additional HMIs as well as backup hardwired control switches and 

indications for critical electrical bus controls. Existing annunciator panels in the main 

control room would be revised to provide alarm windows for the new equipment. Data 

would be provided to the plant process computer (PPC) via a data link to the plant data 

network (PDN). This would allow process data to be displayed on PPC HMIs on the 

operator control consoles in the main control room. 

Communication between the Triconex main chassis and main control room HMIs, 

between the Triconex main chassis and the remote I/O chassis, and between the Triconex 

main chassis and the plant data network would be via new redundant fiber optic cables. 

A relatively small number of hardwired circuits would be required from the cooling 

tower electrical room to the intake structure or directly to the turbine building. In the 

former case, it is expected that existing circuits between the intake structure and the 

turbine building could be reused. In the latter case, the new circuits could be run with the 

fiber optic cables. I/O circuits from new equipment to Triconex and Bently Nevada 

equipment would be hardwired. By locating the Triconex I/O chassis near the 

equipment, circuit lengths would be reduced. 

Uninterruptible Power Supplies (UPS) would be required for the new Triconex and 

Bently Nevada equipment. There would be a UPS in the cooling tower electrical 

equipment room and a UPS in the intake structure for each unit. Operating parameters 

and alarms would input to the Triconex and this information would be available at the 

main control room and HMIs in the cooling tower electrical room. 

The control system would provide manual start and stop capabilities for equipment and, 

where appropriate, automatic sequenced operation of equipment (e.g. cooling tower fans) 

during startups and shutdowns. Cooling fan starts would be sequenced based on unit load 

via a signal from the existing main turbine control system (MTCS). 

Changes would be required to the existing MTCS. A turbine load signal would be 

needed to the circulating water control system. Existing logic that reduces turbine load 

upon loss of a circulating water pump would require changes. A turbine trip upon 13.8 

kV bus undervoltage may be desirable in addition to the existing turbine trip on low 

vacuum. The existing MTCS cannot accommodate significant additional logic since it is 

heavily loaded. Changes are expected to be minimal so are not expected to require an 

upgrade to the MTCS. 

Changes to the reactor trip logic are not anticipated but would need to be investigated if 

this project was to be implemented. If required, this could result in changes to the solid 
29 of 59 

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state protective system (SSPS) inputs and changes to significant numbers of plant 

drawings, documents, and procedures. 

V. Nuclear Safety and Licensing 

1. Nuclear Safety System Requirements 

Retrofitting Diablo Canyon with closed loop cooling towers creates several nuclear safety 

issues that would have to be addressed. It is most likely that these issues would require 

Nuclear Regulatory Commission (NRC) review and approval via License Amendment 

Requests (LARs) to insure an acceptable level of safety. There is a risk that such issues 

could result in LARs that would not pass the NRC review and approval process. As 

noted previously, retrofit of the ASW system to a closed-cycle cooling configuration is 

not feasible from a Nuclear Safety and Licensing perspective. The nuclear safety related 

issues include: 

• Flooding

The condenser cooling water system is a nonsafety related system and is not 

required for the safe shutdown of the plant. However, flooding caused by 

failure of the system in the area of the condensers could jeopardize safety 

related systems located in the turbine building (Emergency Diesel Generators, 

Component Cooling Water heat exchangers, safety related conduits and 

controls). The Diablo Canyon Final Safety Analysis Report (FSAR) discusses 

the possibility of flooding from the cooling water system, and the attributes of 

the system that lessen the risk due to flooding. Key to those attributes is the 

present low pressure in the condenser waterboxes and a circulating water 

pump trip upon high water in the turbine building sump. With the present 

system, after a circulating water pump trip and coastdown, the water in the 

large conduits would drain by gravity flow back to the ocean and not into the 

turbine building. Retrofitting the present system with cooling towers 

adversely changes both these system attributes – the waterbox pressure would 

approximately double, and after a pump trip, large quantities of water in the 

circulating water pipes (now at an elevation higher than the condensers) 

would gravity drain into the turbine building. This increase in flood risk 

would have to be addressed in the FSAR Update and may not be acceptable to 

the Nuclear Regulatory Commission (NRC). 

• Salt Deposition – Increase in Plant Trips

As discussed further under “Air Quality – Plume / Salt Drift”, there would be 

significant salt deposition on the power lines leaving the plant giving rise to 

an increase in the frequency of plant trips due to “loss of off site power”. 

Although the plant is designed to safely shut down after such an event, it 

would result in an increased reliance on the plant safety systems which 

increases the plant safety risk, and is a topic of interest to the NRC. 
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March 2009 

• Salt Deposition – Accelerated Aging of Plant Equipment

Salt deposition from the cooling towers would have the general effect of 

increasing corrosion, required maintenance, and frequency of failure of 

exposed plant equipment. For example, with a southeasterly wind the plume 

could engulf the safety related Emergency Diesel Generator (EDG) ventilation 

intakes. This would accelerate the corrosion problems with the EDG radiators 

(already a problem with existing salty air), and may cause operational 

problems with the EDG controls. See further discussion under “Air Quality – 

Plume / Salt Drift” 

 

• ASW System Interruption

The massive and complex construction excavation activities west of the 

turbine building necessitated by the cooling tower retrofit would increase the 

probability of interruption of the safety related Auxiliary Saltwater (ASW) 

cooling system during construction. Even during plant shutdown, the ASW 

system is required for spent fuel pool cooling. The NRC may prohibit this 

increased risk of disruption of the safety related ASW cooling system, and 

may require an alternate means of cooling the spent fuel pools. 

• Loss of Offsite Power

The past plant design basis was to withstand a full load rejection without a 

reactor trip by running back the turbine. The plant would remain online 

powering the house loads off the 25 kV bus. With the recent replacement of 

the steam generators, the design basis of the plant has been changed to a 50% 

load reduction rather than a full load rejection. However, previous plant load 

rejection controls are still functional, and there are scenarios in which the 

reactor will not trip and the turbine generator will continue to supply house 

loads (including the reactor coolant pumps and the circulating water pumps) 

after both 500 kV breakers open. If cooling towers were installed, power to 

the circulating water pumps would no longer be from the 25 kV generator 

output bus but from the 500 kV system. Similarly, power to the new cooling 

tower fans would be provided from the 500 kV system. Therefore, unlike the 

existing system, condenser vacuum would be lost if both 500 kV breakers 

open. Existing protective systems would result in a turbine low vacuum trip 

and subsequent reactor trip. It may be necessary for protective logic to be 

implemented to immediately trip the reactor when both 500 kV breakers open 

rather than relying on an eventual low vacuum turbine trip. This would 

require changes to the SSPS inputs and changes to significant numbers of 

plant drawings, documents, and procedures. Further study of this issue and 

NRC review and approval would be required if the project were implemented. 

• ISFSI Haul Road Rerouting 

Hauling dry casks of spent fuel from the Fuel Handling Building up to the 

ISFSI storage area has been described in the ISFSI FSAR, and has been 

reviewed/approved by the NRC. The haul road is important to safety and has 

several requirements including a maximum slope of 8.5%, as well as support 

of loadings from the dry cask transporter. The present route has avoided 
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March 2009 

existing and future landslide-prone areas and has been designed to withstand 

the effects of a Hosgri Fault earthquake while encumbered with a loaded 

transporter without the transporter being damaged (tipping over). Therefore, 

the new routing of this haul road due to the installation of cooling towers and 

their auxiliaries would require a new detailed analysis and review/approval by 

the NRC. 

• Landslide Potential 

Certain areas of the site are active landslide zones. The relocation of the 

ISFSI haul road, as well as the location of the cooling towers and their 

auxiliaries, would need to be located to avoid areas of anticipated future 

landslides. This issue would be subject to NRC scrutiny. 

• Fire Protection System Interruptions During Construction 

The NRC would have concerns with the possibility of any compromises to the 

fire protection system, such as accidental damage to the yard fire loop, which 

could occur during construction. This is a risk since extensive excavation 

would be required for the cooling towers and concrete tunnel construction. 

• Security During Construction 

The massive excavations and disruptions of normal site security boundaries, 

and the large numbers of construction personnel and equipment crossings of 

Protected Area (PA) boundaries, would be of concern to the NRC. 

2. NRC Licensing 

NRC regulations 10 CFR 50.59, 10 CFR 50.90 and 10 CFR Part 51 govern proposed 

changes to a nuclear plant. These regulations specify when prior NRC review and 

approval of plant changes is necessary. As part of a cooling tower retrofit, PG&E would 

perform a 10 CFR 50.59 evaluation in accordance with the guidance provided in Revision 

1 of NEI 96-07 and Regulatory Guide 1.187, both dated November 2000. As discussed 

previously in this report, retrofitting Diablo Canyon with closed loop cooling towers 

creates several nuclear safety issues that in accordance with 10 CFR 50.59 would require 

NRC review and approval via the License Amendment Request (LAR) process (10 CFR 

50.90 and 10 CFR Part 51). These issues include the increased risk of flooding of safety 

related equipment, the increased risk of plant trips and accelerated aging of plant 

equipment due to salt deposition, the rerouting of the ISFSI haul road, and the risk of 

disruption of the ASW system during construction. There is a significant risk that that 

the NRC would not be willing to grant a license amendment to allow the change in design 

that creates or increases these nuclear safety issues. Also, the NRC will need to ensure 

that the National Environmental Policy Act (NEPA) is appropriately implemented for the 

environmental effects of the proposed cooling towers construction and operation. In 

order to request NRC approval, the final design must be completed, applicable State 

permits issued, and an LAR prepared and submitted to the NRC. The NRC review period 

typically takes one year after submittal of the LAR. In addition, it is anticipated that 

interveners would request NRC hearings. NRC hearings could take two to three 

additional years. 
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March 2009 

3. Security 

Retrofitting cooling towers at DCPP would have a major impact on site security. The 

plant PA boundary would have to be ultimately relocated to accommodate the installation 

of the cooling towers and their auxiliaries. The boundary for this would be 

approximately in the same area to the southeast of the power block, with the cooling 

towers, circulating water pumps, and the associated electrical buildings being located 

outside the PA. The relocated main warehouse would also be located outside the PA. 

VI. Environmental Impacts and Permitting

1. Air Quality – Plume / Salt Drift 

Significant visible plumes would be generated by cooling towers at DCPP, and would be 

frequently visible from San Luis Obispo and/or Avila Beach. The largest plumes would 

have lengths exceeding 5 miles and heights exceeding 2,500 feet. 

Background: When the ambient air is cooler than the moist cooling tower exhaust air, it 

cannot absorb all the moisture, and the excess moisture in the exhaust air stream 

condenses creating a visible plume. Under certain conditions, a cooling tower plume 

presents a significant fogging hazard to its surroundings. The water evaporated in the 

cooling process is "pure" water, in contrast to the drift droplets carried along with the 

plume. “Drift” is the water droplets that become entrained in the air stream as it passes 

through the cooling tower. The rate of drift loss is a function of cooling tower design and 

configuration, airflow rate through the cooling tower, and water loading. Drift droplets 

have the same or greater concentration of impurities as the water entering the cooling 

tower. Because the drift contains the minerals and chemicals of the makeup water, 

contact of these salts and chemicals with plants, building surfaces, and human activity 

can be detrimental and/or hazardous. Sedimentation of drift droplets downwind of the 

cooling towers would result in an increase in ground level concentrations of salt 

chemicals. 

Due to their size and the limited space available at DCPP, plume-abated cooling towers 

could not be located at the plant site. They are larger than the nonplume-abated cooling 

towers being evaluated in this study, and require a significantly larger footprint. The 

plume-abated cooling towers have a greater height required for the cooling tubes and 

additional fans for the incoming hot water. For proper operation they also need to have 

air coming in from both sides ruling out the back-to-back rectilinear arrangement selected 

for the nonplume-abated cooling towers. The only layout possibilities for plume-abated 

cooling towers would either be circular or extended rectilinear footprints with a width of 

only one cell and a length necessary for 40 cells (~2,400’). Neither configuration is a 

possibility given the characteristics of the site discussed elsewhere. The tubes would 

have to be titanium for corrosion resistance. The fan power would be about double what 
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March 2009 

the nonplume-abated cooling towers consume. The cost for plume-abated cooling towers 

is at least 150% of that for nonplume-abated cooling towers. In summary, the lack of a 

suitable location has ruled out plume-abated cooling towers for DCPP. 

To determine the environmental impact of cooling towers at DCPP, the seasonal/annual 

cooling tower impact (SACTI) prediction code was utilized along with the cooling tower 

design data and local meteorology data. The SACTI software is described by the NRC in 

Section 5.3.3.1 of Standard Review Plan, NUREG-1555, as appropriate for this purpose. 

For purposes of this study it is assumed that both units are operating at 100% power. 

As noted previously, accurate Diablo Canyon site specific data for humidity or wet bulb 

temperature is not available. Therefore, for purposes of this study, hourly wet bulb 

temperatures for the years 2003 through 2007 were taken from the National Weather 

Service (NWS) station at the San Luis Obispo (SLO) Airport. Site specific wind velocity 

and direction data for DCPP was utilized. The SLO Airport weather station data gives 

lower wet bulb temperatures (due to drier inland conditions) than would be experienced 

at the Diablo Canyon site. The use of these lower wet bulb values rather than site 

specific coastline data results in smaller predicted plumes (provides a conservative study 

bias). 

A summary of visible plume lengths that would result from cooling towers at 

DCPP is presented in Table 5. Plumes greater than 1/3 of a mile in length would 

be present approximately 73% of the time during winter and 60% of the time in the 

fall. Plumes greater than 2 miles in length would be present approximately 35% of 

the time during winter and 25% of the time in the fall. In most cases, the plumes 

tend to lie either towards the northwest (over the plant itself, especially in the 

winter) or to the southeast (along the access road from Avila Beach). 

Winter Spring Summer Fall 

Most Frequent 

Plume Heading 

Directions 

NW,SE SE,ESE,SSE SE,ESE SE,ESE,SSE 

Percent of 

Plumes < 1/3 

miles 

26.9 35.0 44.2 40.4 

Percent of 

Plumes >1/3 to 

2 mile 

38.5 28.2 30.3 34.8 

Percent of 

Plumes >2 to 5 

miles 

30.3 32.8 24.3 22.5 

Percent of 

Plumes >5 

Miles 

4.3 4.0 1.3 2.2 

Table 5: Visible Plume Length Frequency Summary – Percent 
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Table 6 shows the percent of time for various centerline heights of the plumes above the 

tops of the proposed cooling towers. The highest plumes, like the longest ones shown in 

Table 5, extend down the coast in the ESE to SSE direction. 

 <100m 

(<330 ft) 

100 - <500m 

(330 - 1640 ft) 

500-<750m 

(1640 - 2460 ft) 

750 - 810m 

(2460 - 2700 ft) 

Total 

Percent 

S 0.43 0.36 0.71 1.5 3 

SSW 0.26 0.39 0.66 1.22 2.53 

SW 0.35 0.49 0.86 1.4 3.1 

WSW 0.39 0.42 0.67 1.3 2.78 

W 0.38 0.4 0.83 1.6 3.21 

WNW 0.23 0.78 1 2.55 4.56 

NW 0.56 1.89 1.94 4 8.39 

NNW 1.24 2.51 1.26 1.93 6.94 

N 1.36 1.02 0.62 0.97 3.97 

NNE 0.43 0.52 0.3 0.45 1.7 

NE 0.36 0.44 0.27 0.37 1.44 

ENE 0.43 0.42 0.22 0.31 1.38 

E 1.24 0.75 0.49 0.76 3.24 

ESE 7.44 2.87 1.29 2.08 13.68 

SE 13.81 3.34 3.8 9.75 30.7 

SSE 1.44 0.71 1.87 5.36 9.38 

All 30.35 17.31 16.79 35.55 100.00 

Table 6: Plume Heights – Centerline Height Percent by Direction 

Plume visibility by calendar time is not an output of the SACTI program, but 

estimates can be made based on the frequency of conducive meteorological 

conditions. Such an estimate determined that plumes would be generated of 

sufficient size to be seen from Avila Beach between an hour before sunrise and an 

hour after sunset approximately 45 times per year, and from San Luis Obispo 

approximately 300 times per year. The plumes would be visible from San Luis for 

approximate 200 sunsets per year. 

Estimates of salt, TDS, PM10, and water deposits are given in Tables 9a, 9b, 9c, 

and 10 of Appendix A-7. Due to the use of saltwater, the salt deposition rates are 

notable for some distance. The five miles of plant access road along the coastline 

will be exposed to some amount of salt. The makeup of the total dissolved solids 

is over 75% sodium chloride. The total annual salt deposition would exceed 7,500 

tons. 

Buildup of salt on the transformers, conductors, and insulators associated with the 500 

kV system would require continuous attention in the form of frequent water washings and 

monitoring of the system to minimize flashover incidents. The power generation industry 
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March 2009 

experiences significant problems caused by salt buildup on electrical systems at plants 

which are less exposed to salt deposition than that which would be seen at DCPP should 

cooling towers be installed. Numerous plants located on coastal areas, e.g., SONGS in 

Southern California, Turkey Point in Florida, and Brunswick in North Carolina, have 

experienced flashover of high voltage equipment due to excessive accumulations of salt. 

(Reference Nuclear Industry OE 21874, OE 21784, and SER 10-93). To combat the 

problems of excessive salt buildup, operators have found it necessary to increase the 

frequency of water washing. Also, increased vigilance is placed on monitoring electrical 

measurements associated with the transmission system to obtain early warnings of 

flashover in order to avoid equipment damage. 

At DCPP, salt drift from the cooling towers would deposit large quantities of salt in a 

broad radius surrounding the cooling towers (Reference Table 8 for Adverse 

Environmental Impacts). The amount of salt deposits on the exposed high voltage 

electrical components would greatly increase over the existing salt deposition rates. 

Frequent washings and monitoring would be required – at a minimum. Precise 

predictions of increased outages due to electrical flashover of equipment attributable to 

excessive salt buildup associated with cooling tower drift is not possible, but an increase 

in such outages with attendant interruption of generation would be expected. The 

alternative of locating high voltage transmission lines underground between the generator 

step up transformers and the switchyard is extremely costly and of questionable 

reliability, and has not been considered in this study. 

Shading and fog from the plumes are given in Tables 11 and 12 of Appendix A-7. 

There will be some loss of sunlight near the cooling towers. The fogging is 

predicted to interact directly with plant components to the NW and plant worker 

and equipment or commercial transport vehicles approaching from the SE. 
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March 2009 

Figure 13 – Cooling Tower Plume (Looking North) 

Figure 14 – Cooling Tower Plume (Looking Southeast) 
37 of 59 

March 2009 

 

Palo Verde – Mechanical Draft Towers 

in a Dry Environment 

 

Cattenom 

 

Palo Verde 

Washington Public Power #2 

Cattenom 

Figure 15 – Plumes from Nuclear Power Plant Cooling Towers 
38 of 59 

March 2009 

2. Water Quality – Cooling Tower Blowdown 

Each unit would require a steady state blowdown flow of approximately 25,200 gpm 

when running at full load. The concentration of the circulating water would be 1.5 times 

normal seawater. Thus the blowdown would have a concentration of about 52,500 ppm 

TDS given an average seawater concentration of 35,000 ppm TDS. The blowdown 

stream is toxic to marine life due to the higher TDS concentration, therefore it would 

either have to be rapidly diluted with ambient seawater as it is introduced into the ocean 

or it would have to be treated to reduce its TDS concentration back to that of seawater. 

Technology exists for removing salt from concentrated waste streams. The technology is 

known as zero liquid discharge (ZLD) and typically involves successive stages of reverse 

osmosis, brine concentration, followed by crystallization where a salt cake is created. At 

DCPP the waste stream of concentrate obviously could not be put back into the ocean, so 

the salt cake would have to be dried and trucked offsite to a waste disposal facility. 

Besides this waste disposal activity, the main disadvantage of ZLD for this application is 

the very high cost of the equipment and the high levels of electric power required. A rule 

of thumb for power requirements for ZLD (per discussion with Aquatech) is 15 kW of 

power are required for each gpm of waste stream to be treated. Thus, for DCPP’s waste 

stream of 25,200 gpm per unit that would mean 378 MW of power. In DCPP’s case this 

power is overstated since not all the dissolved solids would be extracted from the 

blowdown, but rather just about 1/3 of them in order to achieve a TDS level equal to the 

ocean. However, DCPP would still require the brine concentrator and crystallizer 

systems since whatever salt levels removed would have to be trucked away in solid form. 

Brine concentrator and crystallizer engineering and operation is fraught with challenges 

because of scale buildup on the heat exchange surfaces as well as corrosion. Dryer 

operation is also problematic. Periodic acid cleaning of the systems is required. 

Due to the problems associated with ZLD systems as described above, they are not 

considered practical for the massive application that would be required for DCPP. 

Rather, the blowdown stream would be mixed with receiving waters by use of diffuser 

arrays in order to mitigate the effects of the concentrated wastewater stream on sea life. 

Plant effluent salinity within 10% of ambient has been provided (regulator guidance) as 

the acceptable range for discharge permit approval if the outfall configuration does not 

facilitate rapid diffusion in the ocean receiving water. This concentration range cannot be 

achieved even with dilution of cooling tower blowdown with the 51-mgd remaining 

once-through cooling volume proposed for the ASW/SCW systems (72-mgd at 1.5x 

combined with 51-mgd at 1.0x results in a discharge salinity of approximately 1.3x). 

Therefore, the cooling tower blowdown cannot be permitted for discharge to a single 

shoreline or submerged outfall point without substantial additional dilution water sources. 

Other plant effluent streams (including freshwater wastewater streams) do not provide 

enough volume to appreciably impact dilution. Additionally, use of excessive amounts of 

ambient seawater purposefully drawn into plant systems to achieve acceptable outfall 

salinity would be counter to any retrofit effort implemented to minimize seawater use. 
39 of 59 

March 2009 

The only practical option for rapid dilution to ambient salinity is use of a diffusion 

system spread across an acceptably large area in the receiving water body. For this

application, a seafloor-anchored diffuser piping array placed out from the shoreline and 

intertidal zone would be required to reduce or eliminate potential negative impacts to 

receiving water quality and marine life. 

Of specific concern for cooling tower blowdown (in addition to necessity for rapid 

dilution in receiving waters) are the Effluent Limit Guidelines (ELGs) for select 

constituents. These ELGs are specific for point of discharge from cooling tower systems, 

and not for final concentrations detected at a facility’s combined wastewater outfall. 

Chromium (Cr) and Zinc (Zn) have blowdown ELGs of 0.2 mg/L (milligrams per liter or 

parts per million) and 1.0 mg/L respectively. An assessment of intake seawater (influent) 

samples taken monthly for DCPP during the period 2005-2007 determined that Cr was 

almost exclusively non-detectible with one value of 0.2 ug/L (micrograms per liter or 

parts per billion) concentration during the period. Zn was also routinely non-detectible; 

however, several instances of detection did occur with a maximum concentration of 59 

ug/L during the period. For both of these constituents, concentration factors of 1.5x or 

even 2.0x in cooling tower blowdown would not result in an exceedance of the process 

specific ELGs provided available makeup at DCPP continued to exhibit low 

concentrations. Other cooling tower blowdown priority pollutant ELGs should likewise 

not be problematic provided ambient seawater chemistry off the plant site remained 

stable. 

Closed-cycle systems tend to exhibit more alkaline pH than makeup water. For DCPP, 

ambient seawater normally has a pH in the range of 7.8 to 8.4. This pH range facilitates 

chlorine/bromine control of biological fouling in existing seawater systems. As discussed 

previously in this report, the high salinity projected for cooling tower system operations 

should reduce or eliminate macrofouling concerns (primarily marine barnacle and mussel 

fouling) within the system. However, fouling of main condenser tube surfaces might still 

occur under certain conditions due to micro-organisms capable of withstanding the high 

salinity. This could require periodic chlorination treatment of the main condensers. 

However, such treatment would be hindered by elevated pH conditions. Acid 

(hydrochloric or sulfuric acid) injection to depress system pH could be necessary in order 

to facilitate microfouling oxidation treatment within the main condensers. It is not 

anticipated that addition of inorganic acids to effect moderate pH depression would 

negatively impact overall water quality in the system, or subsequently reduce the ability 

to discharge the blowdown. 

Chlorine treatment on an as-needed basis injected immediately upstream of the main 

condenser inlets could be accomplished with only a temporary increase in residual 

oxidants within the system. The cooling tower blowdown may require temporary 

isolation in the event residual chlorine was persistent. If actual operations required 

extended chlorination treatment, or resulted in excessive residual chemical 

concentrations, cooling tower blowdown dechlorination capability could be required. 

Actual need for pH moderation, main condenser biofouling treatment, and/or periodic 

cooling tower blowdown dechlorination is highly speculative. Therefore, equipment 
40 of 59 

March 2009 

specifications and costs to implement these processes have not been considered in this 

study. 

The blowdown stream would be taken from the cold side of the cooling towers, having a 

maximum temperature of 83°F given a “maximum” wetbulb temperature of 66°F (this 

“maximum” wetbulb represents a point 2 standard deviations to the right of the mean 

wetbulb value of 52.0°F, representing all but 193 hours per average year when the 

wetbulb is greater than 66°F). 

Blowdown would be directed into a pipe from a weir gate at the pump pit to achieve the 

desired flow. From there the pipe would be directed to the ocean near Patton Cove, south 

of the intake cove. The temperature and concentration of the blowdown being higher 

than that of the seawater would result in a density of 64.7 lb/cu ft, as compared with a 

seawater density of 64.0 lb/cu ft. Being heavier, the blowdown stream would tend to sink 

amid the seawater, with negative effects on benthic marine communities. To counter this 

tendency, the blowdown stream would be channeled through diffusers at a high velocity, 

(5 ft/sec minimum) in order to promote mixing with the surrounding seawater. The 

blowdown distribution system would consist of a large distribution header, approximately 

36”, which would be filled from a weir at each circulating water pump pit where the flow 

could be set for a steady state flow of 25,200 gpm per unit, and would discharge under 

water on the sea floor (Reference Sketch SK-M-4). On the top of the underwater pipe 

would be located an array of diffuser nozzles (approximately 600 11⁄2-inch diameter 

nozzles). Given equal flow they would each have a discharge velocity of 6.6 feet per 

second. At this velocity, the concentrated stream would be forced to mix with the less 

concentrated seawater as it exited the nozzle. Static head from the 85 foot elevation at 

the inlet of the blowdown line would provide the driving force for the flow. The nozzles 

would be located on 1 foot centers, two at each station, symmetrically configured 

pointing upward at an angle of 60° from the horizontal. The diffuser section of the piping 

would start 200 feet from shore and extend another 300 feet for a total of 500 feet per 

unit. Fiberglass would be a suitable material for the diffuser system. 

The blowdown plume was modeled with CORMIX, a comprehensive software system for 

the analysis, prediction, and design of outfall mixing zones resulting from the discharge 

of aqueous pollutants into diverse water bodies. It contains mathematical models of point 

source discharge mixing within an intelligent computer-aided design interface. The 

programs focus is environmental impact assessment and regulatory management. It has 

been developed under several cooperative funding agreements between U.S. EPA, U.S. 

Bureau of Reclamation, Cornell University, Oregon Graduate Institute, University of 

Karlsurhe, Portland State University, and MixZon Inc. during the period 1985-2007. 

CORMIX is a recommended analysis tool in the permitting of industrial, municipal, 

thermal, and other point source discharges to receiving waters. The system’s major 

emphasis is on predicting the geometry and dilution characteristics of the initial mixing 

zone so that compliance with water quality regulatory constraints may be judged. 

CORMIX was used to evaluate the thermal and total dissolved solids (TDS) plumes that 

would be discharged as a result of the closed-cycle cooling installation. The expected 
41 of 59 

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thermal plume from the diffuser array ports was found to be 0.80 meters (2.6 feet) long 

before reaching the 2.78oC (5oF) isotherm above the ambient. The expected TDS plume 

was found to be approximately 0.77 meter (2.5 feet) long. The current thermal discharge 

associated with the once-through cooling system is much larger, has an average thermal 

differential of approximately 11.1oC (20oF), and dissipates from a single shoreline 

outfall. An amendment would be required to the power plant’s NPDES Permit to define 

the modified thermal discharge characteristics, including use of the entirely new offshore 

diffuser array. The actual plant discharge has not been designed, but the results provided 

would be bounding for any similar discharge. Table 7 summarizes the CORMIX results: 

Plume Type 

Ocean 

Temperature 

°C (°F) 

Discharge Flow 

Rate (Per Unit) 

m3

/s (gpm) 

Isotherm 

Considered 

°C (°F) 

Plume Length 

 m (ft) 

Thermal 9.33 (48.8) 1.59 (25,200) 2.78 (5) 0.80 (2.6) 

TDS 9.33 (48.8) 1.59 (25,200) 2.78 (5) 0.77 (2.5) 

Table 7: Summary of Thermal Plume Analysis 

DCPP is currently permitted to return wastewater to the ocean at a temperature of no 

more than 22oF higher than ambient seawater intake temperature. It has been assumed 

that a reconfigured DCPP would be required to meet the 20oF limit above ambient 

receiving water temperatures for a ‘new’ discharge in accordance with the California 

Thermal Plan. Since the cooling water blowdown would always be 17 oF higher than the 

wet bulb temperature, there would be numerous occasions when the blowdown 

temperature would be more than 20oF above the ocean temperature. Examination of wet 

bulb temperature and ocean temperature at the intake structure show that the differential 

temperature would exceed 20oF approximately 25% of the time. The use of SLO Airport 

weather station wet bulbs, which are likely lower than the wetter immediate coastal zone, 

adds a bias which tends to reduce the estimated hours per year that the blowdown would 

exceed the ocean water temperature by more than 20oF. 

Figure 16 shows the hours per day that the blowdown would exceed the ocean water 

temperature by more than 20°F (based on data from the years 2003 – 2007). Note that 

the limit is rarely exceeded in winter, but often in summer. 

0

5

10

15

20

25

 1/1/2003 1/1/2004 1/1/2005 1/1/2006 1/1/2007 1/1/2008 

Figure 16 – Hours/Day that the Blowdown Water Temperature Would Exceed the 

Discharge Limit 
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Under such conditions it would be necessary to cool/dilute the blowdown stream with a 

colder stream such as the service cooling water seawater supply or the makeup water 

system. For purposes of this study, a 20” branch from the SCW seawater supply would 

be routed to the inlet of the blowdown line to achieve the desired mixing. During these 

periods when blowdown temperature reduction is required, it would be necessary to run 

the third SCW supply pump. This would result in an additional volume of raw seawater 

use during these periods. 

3. Adverse Impacts 

Retrofit of DCPP to closed-cycle cooling would create significant adverse environmental 

impacts. These direct adverse impacts, as discussed below, would be realized both 

during implementation of the project, as well as during post-retrofit operation of the 

facility. Additionally, the large workforce, and transportation of equipment and materials 

required during the construction phase, would generate negative impacts to the immediate 

surrounding communities. Personnel transportation to and from the facility would 

substantially increase light vehicular traffic in the immediate area for an extended period. 

Heavy equipment and materials trucking would significantly impact traffic flow and 

generate appreciable road noise. 

The project would generate significant adverse impacts related to overall electric industry 

green house gas (GHG) emissions. Loss of DCPP Units 1 & 2 for an extended period of 

time during construction (projected at 17 months minimum) would require replacement 

of the entire base load generation capacity of the facility. This lost electric supply would 

most likely be replaced throughout the period of construction with higher utilization of 

available fossil fuel generation units. Additionally, the permanent loss of unit efficiency 

and increase in required auxiliary power for the cooling tower system operations would 

result in an ongoing reduction in net base load generation. This post implementation 

reduction in electric generation capacity would need to be replaced by other base load 

generation facilities (fossil units). The loss of long term capacity would effectively 

reduce future supply gains from planned efficient fossil and renewable resource 

generation projects in the State. 

Demolition, construction, and transport activities associated with a retrofit project would 

be substantial. The very large equipment associated with these activities would rely on 

diesel combustion, and therefore result in substantial consumption of fuel oil as well as 

the associated onsite emissions of GHG and particulates. Most construction activities 

would occur within the existing, previously disturbed, site industrial areas. However, the 

placement of a discharge dispersion system on the seafloor offsite of the plant would 

disrupt and segment pristine rocky marine habitat, as well as disrupt transited intertidal 

zones during pipe placement. The large demolition and new construction projects would 

also generate substantial volumes of related debris. Metals, wood, concrete, and asphalt 

can be recycled; however they would still require offsite transport resulting in additional 

fossil fuel consumption. Non-recyclable fills, plastics, equipment and existing building 
43 of 59 

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materials would need to be transported offsite as well, and disposed in limited available 

landfill space. 

Salt emissions from the saltwater makeup mechanical draft cooling towers would present 

a significant new adverse impact at the plant site. Salt drift would plague the entire 

industrial site and all exposed plant equipment, as well as settle on surrounding lands. 

The deposition of salt to the terrestrial plant and animal community on coastal bluffs 

southeast of the facility would dramatically increase, far in excess of the natural 

contamination from winds coming off the adjacent sea. Additionally, substantial vapor 

plumes from the cooling tower complex would be visible during certain periods to 

surrounding communities. 

Operation of the cooling tower systems would generate large volumes of high salinity 

elevated temperature blowdown requiring disposal to the Pacific Ocean. Construction of 

the diffuser system for discharge of the blowdown would disrupt the existing seafloor 

community, and operation of the system could result in establishment of high salinity 

zones potentially toxic to microscopic organisms in the immediate vicinity of diffuser 

ports. Such unfavorable conditions could occur in the receiving water when currents are 

low and ocean conditions calm resulting in less efficient mixing and dispersion. 

Since PG&E owns large acreage tracts surrounding the power plant, noise generated from 

the cooling towers, primarily due to the fans, should not be a significant issue at the 

industrial site boundary. However, the cooling towers would increase the ambient noise 

levels in their surrounding vicinity which would impact the occupancy of nearby offices 

and facilities.
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The following table summarizes the projected significant adverse environmental impacts: 

Adverse Impact Cause Projected Magnitude 

Project Implementation (Construction Phase):

Green House Gas (GHG) 

Emissions for Replacement Power 

Unit 1 & 2 Replacement Power During Extended 

Outages. (Lost carbon-free generation most likely 

replaced by fossil-fuel generation.) See Notes 1 & 2. 

10,318,500 Tons CO2 GHG Emissions

Project Fossil Fuel Combustion 

Transport of Construction Equipment, Construction 

Materials, Removal of Spoils, Debris, & Recyclable 

Materials, Onsite Grading & Construction Activities 

and Bussing of Craft Workers. 

> 4.424,000 Gallons of Diesel Fuel. 

Reference Appendix A-10 ,”Fuel 

Consumption Summary” 

Disruption of Benthic Marine 

Habitat 

Area Preparation and Placement of Discharge 

Dispersion Piping on Seafloor. Loss of 0.35 Acres of Rocky Subtidal 

Construction Debris Disposal Landfill of Non-Recyclable (Non-Metal or Wood) 

Construction and Site Debris. 

3,600 Cubic Yards Landfill Disposal 

300 roll-offs filled to 12-cubic yards 

Facility Operations Post-Construction:

Green House Gas (GHG) 

Emissions for Replacement Power 

Generation Required to Replace Unit 1 & 2 

Efficiency Loss & Increased Site Auxiliary Power 

Requirements. (Lost carbon-free generation most 

likely replaced by fossil-fuel generation.). See Notes 

1 & 3. 

180,500 Tons CO2/Year GHG Emissions.

Salt Emissions and Deposition Cooling Tower Salt Drift 

15,000,000 Pounds per Year 

Deposited on surrounding lands & equipment. 

Calculation based on 25 day outages, drift of 

86 gpm and .0405 gm/gm fraction of salts 

(Reference Appendix A-7). 

Vapor Plume Cooling Tower Emissions 

Plume Lengths Exceeding 5 miles 

Plume Heights Exceeding 2,500 feet 

45+ Times/Yr Visible from Avila Beach 

300+ Times/Yr Visible from SLO

Blowdown Discharge Dispersion 

Zone with High TDS 

High salinity and thermal dispersion zone. Potential 

for negative impacts to marine organisms that come 

in direct contact. (Estimate of water volume affected 

by 1200 operating diffuser array nozzles.) 

350 Cubic Meters in Receiving Water 

Estimated high TDS zone above each diffuser 

array: 91m long * 2.5m wide * 0.77m high = 

176 cubic meters per unit

Corrosion Control Emissions 

Site corrosion control initiatives would substantially 

increase including necessity to resurface and paint 

metal equipment and structures. 

> 500 lbs/year Increase in Volatile Organic 

Compound (VOC) Emissions 

 Table 8: Projected Direct Adverse Environmental Impacts of DCPP Retrofit. 

Table 8 Notes: 

1. GHG calculations based on California Public Utilities Commission (CPUC) Greenhouse Gas Emissions 

Performance Standard Documents: 800-900 Pounds of CO2 per MW-Hr provided as emissions from 

efficient combined-cycle turbine natural gas fueled generation. 800 Lbs/MW-Hr used in GHG emissions 

estimates. 

2. GHG emissions for Project Replacement Power During Construction (Unit 1 & Unit 2 Net Generation 

Capacity of 1155 MW/Unit with 17 Month Dual-Unit Outage): 

[2310 MW * 0.9 * 517 Days/project * 24 Hrs/day] = [25,796,232 MW-Hrs] * 800 lbs. CO2/MW-Hr = 

20,636,985,600 lbs. CO2 = 10,318,493 Tons C02 or 9,380,448 Metric Tons CO2. 

3. GHG emissions for Annual Replacement Power Post-Project Operations (Average 55.4 MW Facility 

Reduction in Electric Output & Anticipated 90% Facility Capacity Including One 25-Day Unit Refueling 

Outage per Cycle): 

451,180 MW-Hrs/Yr [Ref. Table 3] * 800 lbs. CO2/MW-Hr = 360,944,000 lbs.CO2/Yr = 180,472 Tons 

C02/Yr or 163,693 Metric Tons CO2/Yr. 
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4. Permitting 

Implementation of retrofitting DCPP to a closed-cycle cooling configuration would 

require a substantial regulatory permitting effort. In addition, due to existing or potential 

restrictive requirements and conditions, the ability to acquire all key construction 

approval and/or post project plant system operating permits would be very difficult. One 

key environmental permit (air emissions permit) presents a potentially insurmountable 

obstacle to project feasibility. Furthermore, no single regulatory agency controls or has 

overriding authority over all required project permits and licenses further complicating 

any permitting assessment. 

In accordance with power plant construction projects in the State of California within the 

last decade, crucial operating permits would have to be secured (or at minimum a firm 

legal commitment obtained from the regulatory agency responsible) before project 

construction could start. These include permits required for unit operations post retrofit. 

Without the assurance that operating permits will be obtainable/approved following 

construction, a power plant retrofit project would be too risky to proceed. For DCPP 

these key permits would include, at a minimum: 1) a substantially revised facility 

wastewater discharge requirements permit (National Pollution Discharge Elimination 

System [NPDES] Permit), and 2) an Air Emissions Permit-to-Operate (PTO) for cooling 

tower operations due to projected substantial PM10 emissions. 

A Coastal Zone Coastal Development Permit (CDP) would be required for the overall 

project from the California Coastal Commission prior to initiating construction. 

Obtaining final Coastal Commission approval for such a project is highly speculative, 

and assurance of post project operating permit and license availability would likely be a 

CDP approval condition under any scenario. Additionally, the fact that plume abatement 

cooling towers are infeasible on the plant site, and frequent substantial vapor plumes are 

projected to be visible from surrounding communities, reduces the likelihood of 

commission approval. Conditions in a CDP would also likely include significant 

mitigation or offsets for environmental impacts of project implementation (construction 

traffic, construction pollution, site aesthetic impacts, salt plume impacts to surrounding 

lands, etc.), and could result in substantial additional project costs that are not included in 

the current estimates. 

Air permitting for mechanical draft wet cooling towers, a key required post retrofit 

environmental operating permit, is problematic for DCPP. San Luis Obispo County is a 

non-attainment region for State of California PM10 air quality parameters. Obtaining a 

permit for significant new PM10 emissions would require substantial emissions offsets 

that currently are not available within the air district. With the projected growth of local 

and state populations, the lack of emissions offsets presents a real and potentially 

insurmountable obstacle to permitting a cooling tower system at DCPP. 
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March 2009 

The implementation of a retrofit would require significant modification to the Power 

Plant’s current NPDES Permit issued by the California Regional Water Quality Control 

Board, Central Coast Region (CCRWQCB). Potential modifications could include more 

restrictive effluent limitations, as well as additional discharge and receiving water 

monitoring. This could add substantially to ongoing facility operation and maintenance 

costs. If the discharge would be considered “new” under the State Thermal Plan (likely 

due to the proposed installation of an offshore diffuser array for tower blowdown), the 

outfall limit would be set at 20°F above ambient receiving water temperatures. The 

thermal limit could necessitate periodic unit power reductions, and/or the use of 

additional raw seawater for mixing with tower blowdown (Reference Report Section III.2 

Conceptual Design Summary). 

As previously discussed, the only practical/viable option for discharge of the large 

volume of high salinity cooling tower blowdown is diffusion offshore. Construction of 

an offshore piping system would require a State tidal and submerged lands lease and 

Army Corp of Engineers permit before the overall retrofit project could begin. 

Additionally, approval for diffuser system installation would be a prerequisite for 

obtaining NPDES Permit approval. The scenario of nested regulatory approvals would 

necessitate significant administrative lead time for wastewater discharge system related 

permit and license authorizations, and to insure timely sequenced resolution. 

Approval of all project related Local and State permits, or at a minimum firm agency 

commitments to provide final approval for fully developed draft permits, would be 

necessary to support NRC licensing for the extensive nuclear plant modifications. 

Estimates of lead time for various administrative efforts reflect allowances to adequately 

resolve anticipated Local and State permitting challenges prior to submittal of an NRC 

Operating License Amendment Request (LAR). 
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March 2009 

The following table summarizes anticipated project permit and licensing requirements: 

Regulatory Agency Permit Type & Function 

Administrative Allowance 

(Begin Documentation 

and Permitting Process) 

Probable Constraints & 

Significant Special Conditions 

Project Implementation/Construction Permits:

California Coastal 

Commission 

Coastal Zone Development Permit 

(CDP). (Overall Project Construction 

and Building Authorization Permit) 

3-Years prior to project 

NRC LAR Submittal. 

Obtain key environmental 

operating permit commitments 

before overall project approval. 

Special conditions and offsets. 

County of San Luis Obispo Project Component Building 

Permits(s) & Grading Permits. 

3-Years prior to project 

NRC LAR Submittal. 

(In conjunction with CDP) 

Special conditions and offsets 

likely required. Scope unknown. 

U.S. Army Corps of 

Engineers (ACE) 

Section 404 Nationwide Permit 

(NWP) for Structural Discharge. 

(Permit for seafloor dredging and 

materials placement for offshore 

wastewater diffuser array) 

5-Years prior to project 

NRC LAR Submittal. 

(Commitment to support 

NPDES permitting effort) 

Seafloor damage and disruption 

mitigation likely required. 

California State Lands 

Commission (SLC) 

Right of Way (ROW) and Lease for 

Tidal and Submerged Lands at Patton 

Cove. (Lease for wastewater diffuser 

array lands use) 

5-Years prior to project 

NRC LAR Submittal. 

(In conjunction with ACE 

Section 404 permit effort) 

Unknown 

State Water Resources 

Control Board (SWRCB) 

Construction Storm Water Discharge 

Permit. (Required for project >1 acre 

of ground disturbance) 

4-Months prior to initial 

construction. 

None-Anticipated. Routine type 

project permit. 

SLO County Air Pollution 

Control District (APCD) 

Concrete Batch Plant Permit-toOperate (PTO). 4-Months prior to batch 

plant operations. 

Dust control measures and fuel 

combustion emissions restrictions 

(if fossil-fueled). 

New/Revised Facility Operating Permits:

Regional Water Quality 

Control Board (RWQCB) 

Central Coast Region-3 

National Pollution Discharge 

Elimination Systems (NPDES) 

Permit. Facility Wastewater Discharge 

Requirements. 

4-Years prior to project 

NRC LAR Submittal. 

(Draft Permit and Agency 

commitment likely required 

before CDP approval) 

No variance from California 

Thermal Plan maximum 

temperature limits. More 

restrictive constituent limitations 

on equipment specific wastewater 

pathways (Sewage, SWRO, etc.). 

SLO County Air Pollution 

Control District (APCD) 

New Cold Machine Shop Abrasive 

Blasting & Painting Unit Air 

Emissions Permit-to-Operate (PTO) 

4-Months prior to initial 

unit operations. 

None-Anticipated. In-kind or 

similar equipment replacement 

for existing unit. 

SLO County Air Pollution 

Control District (APCD) 

Cooling Tower Air Emissions Permitto-Operate (PTO). 

4-Years prior to project 

NRC LAR Submittal. 

(Draft Permit and Agency 

commitment likely required 

before CDP approval) 

Require procurement of PM10

emissions offsets. Offsets are 

currently unavailable and 

potentially unattainable. 

Table 9: Required Construction and Operation Permits & Licenses 

Not Including NRC Nuclear Reactor Operating License Amendments/Extensions for Units 1 & 2 

VII. Additional Studies

1. Special Studies 

Numerous technical issues would require further study at a point during the design phase 

of the cooling tower retrofit. These include (but are not limited to): 

• Circulating Water Pump Pit: It is recommended that the pits be designed by 

modeling studies, which can be done by the circulating pump suppliers, among 

others. 
48 of 59 

March 2009 

• Diffuser Design: Effective diffusion of the heated and concentrated blowdown needs 

to be analyzed further to ensure sufficient mixing would be achieved. 

• Soils Investigations: Additional borings and soil testing is advisable where heavy 

loads are anticipated due to the cooling tower basins and the pump pits. 

• Water Hammer Analyses: Very large water flows can be subjected to high pressure 

spikes or low pressure vacuum formation during transient conditions. These 

fluctuations, known as “water hammer” require analyses to avoid or minimize the 

pressure fluctuations through design features. 

• Cooling Tower/Condenser/Flow Rate Optimization: If the retrofit were to 

proceed, a more detailed optimization of the combined cooling tower performance, 

condenser design, piping size and cooling water flow rate should be performed. 

• Power Plant System Effluents: Further design of a retrofit would require additional 

analyses of a variety of existing effluent streams which would remain even with a 

closed-cycle cooling system. Needed analyses include evaluating the capacity of the 

liquid radwaste system to manage smaller batch discharges, assessing the potential to 

redirect the reverse osmosis system to a newly constructed offshore diffuser, and the 

need to further treat other remaining discharges such as the steam generator 

blowdown, turbine building sump effluent, and makeup water treatment system 

blowdown. In addition, the effect of reduced seawater flows and potential for 

extended periods of stagnation within auxiliary system heat exchangers, would likely 

create challenges due to elevated copper concentrations in the remaining discharge. 

Reference Appendix 13, Power Plant System Effluents Concerns. 

VIII. Conceptual Schedule

1. Introduction 

The conceptual schedule for implementing closed-cycle cooling using mechanical draft 

cooling towers at Diablo Canyon was developed using current regulatory proposals. Start 

dates for construction were chosen to accommodate the 01/01/2021 deadline provided in 

the California SWRCB draft policy for implementing I&E reduction goals at operating 

facilities that use once-though cooling. The schedule provides that both units will be 

shutdown in extended closed-cycle retrofit outages prior to the deadline, with return to 

service and commercial power generation not occurring until after the deadline. The 

schedule also provides for substantial project lead time which will be necessary to 

facilitate extensive permitting, licensing, design, and work planning activities. 

The conceptual schedule is based on both units operating as long as practical 

(approximately 21-22 months) during construction of new site replacement facilities, and 

the cooling tower/site excavation. Initial construction (10 months) involves building new 

site facilities to replace those displaced by the new cooling towers and related services. 

Permitting (SLO County Building, California Coastal Commission, NRC LAR approval, 
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March 2009 

etc.) would be required prior to start of new facility construction. Demolition of 

displaced facilities can begin after warehouse inventories and displaced personnel have 

been moved. Excavation and construction of the cooling towers would then follow. 

Cooling tower basin excavation, re-configuration of the Protected Area (PA) perimeter, 

and start of the Circulating Water Tunnel (CWT) construction between the tower basins 

and the tie-in inside the PA would require that major yard utilities be taken out of service. 

This would initiate the overall plant shutdown. Specifically, loss of service for the 480V 

& 4,160V (non-vital) electrical yard loops would challenge the operability of several 

mechanical systems needed to run the plant. Disruption of the fire loop, domestic water, 

circulating water and other water systems would result. The shutdown and eventual restart would be staggered with 2 to 3 weeks between Unit 1 and Unit 2. During plant 

shutdown and tunnel construction (including tie-ins), both units' ASW piping would 

remain in service supporting CCW. Special protection measures would be in place. 

Several parallel construction paths would be ongoing during plant shutdown: (a) 

Condenser retrofit, SCW piping and other displaced turbine building equipment rework, 

(b) Construction and tie-in of new/existing CW tunnels west of the turbine building, 

including displaced/re-routed utilities, (c) Rework/configuration of the intake structure 

for new makeup and SCW pumps, piping, and related services, and (d) Electrical service 

changes to match new equipment at the intake, the cooling tower basins, and the 500 kV 

switchyard. 

The overall duration for construction would be approximately 3-3/4 years. The plant 

shutdown during the construction period would be at least 17 months. Durations assume 

that engineering design can be developed to support permitting, that permits can be 

obtained, and that the regulatory process does not extend overall construction. 

Anticipated Federal, State, and County (SLO) permitting are included in the schedule. 

2. Schedule Basis, Calendar, Resources 

The schedule assumes an average (plateau) peak work force of approximately 3,000 craft 

between 2nd Q, 2020 and 4th Q, 2021 (18 months). This occurs primarily during plant 

shutdown. Actual peaks within this timeframe could be as high as 4,000. The conceptual 

schedule has not been resource loaded at this level of detail. Bussing from several offsite 

staging areas would be required to reduce the number of automobile trips to and from the 

site. Prior to the plant shutdown, craft requirements would be approximately half the 

peak period level (1,500), and for the last 9 months of construction that number would 

reduce to approximately 1,000 workers. 

The distribution of craft would be such that approximately 2/3 of the above hours are 

based upon 2 x 10 hour/day shifts and a 6 day work week. Non-critical craft would work 

a single 10 hour x 5 days/week shift. 

The construction and engineering activity durations are based upon judgment. Input for 

the overall durations has been reviewed by DCPP System and Design Engineering and 
50 of 59 

March 2009 

Construction Planning. Many of the durations are based upon historical information from 

original construction or more recently completed projects. 

The permanent (existing) plant staff is assumed to remain constant at about 1,250. The 

plant shutdown and on-going construction are expected to require support for capital 

improvement and maintenance projects similar in size and value to those presently being 

conducted during both ongoing operations and refueling outages. 

3. Pre-Shutdown Construction 

Permitting for anticipated Federal, State, and County agencies covers about 7 years; this 

can be adjusted relative to the start of engineering. Design is only shown for the 

replacement facilities. These are the "drivers" for early site construction. Other 

engineering design (cooling towers, pumps, piping, tunnels and supporting system 

changes, and related design) has not been shown on the schedule, but is understood to 

occur in the overall timeframe. Front-end engineering is precedent to the permitting 

process. Final engineering supports site construction and is assumed dependent on the 

permitting process. The initial construction would be for facilities needing to relocate 

before cooling tower construction: main warehouse, cold machine shop, 

engineering/other offices (Parking Lot #7), new sewage treatment plant, new parking 

structure (1,000 spaces) and the vehicle inspection station. Locations for some of these 

are tentative and require more engineering evaluation. Some of these may have to be 

located offsite, or divided to suit multiple smaller (partial) footprints. 

The overall duration to construct new/displaced facilities would be approximately 10 

months, plus 1 to 2 months for personnel and inventory moves. After that, cooling tower 

excavation could proceed (generally) from west to east. Cooling tower basins' grade 

would be at elevation 83' to elevation 85' and would cover approximately 40 acres 

(encompassing Lots #6, 7, 8, the main warehouse and southern portions of Reservoir 

Road). 

Security changes needed to support construction are extensive. These affect the rearrangement of the existing PA fencing, circuitry, and camera/microwave systems. 

During re-work and restoration of the PA, compensatory security measures will be in 

place (24/7) to ensure the integrity of the Plant Security PA Boundary. 

During 2019 through 1st Q 2020, it would be necessary to conduct fuel cask campaign 

operations to ready both fuel pools for full core offloads that occur during the plant 

shutdown(s). Limited access during realignment of Reservoir Road (2nd/3rd Q of 2019) 

could impact ISFSI operations. 

4. Construction During Plant Shutdown 

Excavation of the cooling tower basins, the pump pits and new tunnels between the 

cooling towers and inside the PA would involve interruption of main plant 480V & 4 kV 

electrical systems. As tunnel trenching proceeds past the security building into the PA, 
51 of 59 

March 2009 

the entire southern security boundary must be protected and eventually re-worked. 

Excavation for the tunnels into the PA west of the turbine building expands the number 

of systems to be temporarily shut down and re-configured. It is not practical to reroute or 

try to "jumper" the affected systems because the tunnels' path for both units covers such a 

large area (the planned excavation extends northward past the actual plant centerline 

between Unit 1 & Unit 2). Key vital systems are not allowed to be shut down, but require 

special protection to ensure continued operability. The main fire loop, the ASW piping, 

the diesel fuel oil tanks and piping are among those requiring protection. 

The new circulating water tunnels would require 8 connections to existing tunnels. On 

the supply side, 4 of these would meet the existing inlet tunnels and penetrate them. Tiein of the new tunnels would have to minimize the impact and exposure of the 4 ASW 

supply pipes. These are on the upper opposing CWT walls. The proposed routing avoids 

the ASW pipes on the inner walls and the 480V vital duct banks on top of the tunnels by 

using tie-in routing from the outside or below. Shoring and sequencing of the work in 

getting to the required elevation requires dedicated construction engineering to map, 

expose and protect all of the U/G utilities in the areas. 

The excavation in front (west) of the turbine building and the corresponding reinstallation 

of the affected underground utilities followed by backfill need to be completed before 

and after movement and access of equipment for the main condenser rework and other 

affected equipment on elevation 85' of the turbine building. The PA west of both 

(especially Unit 2) buildings could not support equipment movement during much of the 

first half of 2020. 

During plant shutdown, fuel would be offloaded and stored in each unit’s spent fuel pool. 

Essentially, each unit would be in a 17 month refueling outage. Considerable capital and 

maintenance work would be planned during the shutdowns in addition to the cooling 

tower scope, but is not included in this conceptual schedule or estimate. The ramp down 

and power ascension of both units will be staggered by approximately 2 to 3 weeks. 

Normal unit refuelings and cycle lengths would be utilized for the cycle preceding each 

unit’s shutdown. The schedule for starting construction of replacement facilities in 2018 

and plant shutdowns commencing in early 2020 would be preceded by 1R21 in the 4th Q 

of 2018, and 2R21 in the 4th Q of 2019. Refuelings would not resume until 

approximately 18 months and 21 months after the re-start of commercial operations or 

September of 2023 and February of 2024 in accordance with the conceptual schedule. 

Other critical activities, needed to integrate the new cooling towers, pumps, and hardware 

into the plant, involve construction of a new access road into the back (east) side of the 

powerblock. This occurs at the bench at elevation 115' and allows cask transporter traffic 

between the Fuel Handling Building (FHB) and the ISFSI facility via Reservoir Road up 

the hill. The new road to the bench at elevation 115' must transition approximately 30 ft 

of elevation over almost 400 ft of length. Routing of grading, compaction and paving 

equipment in this area, and overall construction represent a challenge to electrical and 

compressor equipment southeast of the Unit 2 Turbine Building. The Radwaste 
52 of 59 

March 2009 

maintenance and compressor facility would require relocation (related services are also 

affected). Tie-ins for switchgear at the 500 kV Switchyard and main buried electrical 

services down to the power block and the cooling tower basins would take place while 

the plant is shut down. 

No specific line activities are included in the conceptual schedule for control room 

simulator changes. Engineering design and hardware order placement for affected boards 

would be in 2018 and 2019. Physical changes would be done in 2020 to support actual 

operator training in 2021 before restart. 

The new makeup and blowdown lines, between the cooling towers and intake (and the 

cooling towers and offshore diffuser), follow the CWT work and mechanical installations 

at the intake; the work is not critical path. Two 36" diameter blowdown lines are routed 

underground from the cooling tower basins to Patton Cove and then several hundred feet 

offshore to the discharge (diffuser array) location. The existing CWT bores 1-2 and 2-2 

will serve as a corridor for routing the makeup piping from the intake to the new tunnel 

tie-ins inside the PA. The blowdown lines require special engineering, permitting and 

installation to ensure that ocean floor and sea life protection is maximized. The schedule 

has very summary level of detail showing these activities over an approximate 15 

months. 

5. Plant Re-start and Construction Completion 

The schedule assumes that Unit 1 & Unit 2 restarts are on staggered schedules (2 to 3 

weeks apart) to facilitate safe startup operations for each unit. Approximately 2 months 

of startup and testing would precede fuel loading and restart per unit. Reloading of fuel, 

system tests and paralleling each unit to the grid including power ascension would 

require about two weeks. During this period, and the 2 to 3 months preceding, plant 

security must complete all of its final testing of the new, reconfigured, PA boundaries. 

The post-startup duration for construction is about 4 to 6 months. Very little definition 

has been included for these noncritical activities. Backfilling, grading & paving outside 

the PA, noncritical utilities' testing and restoration, signage, painting, training and closeout of all construction packages can all complete after plant restart. 

IX. Cost Estimate Summary

1. Cost Estimate Overview 

The cost of retrofitting DCPP with mechanical draft cooling towers is comprised of 5 

elements; 1) Capital Project Cost, 2) Decommissioning Cost, 3) Operation and 

Maintenance Cost, 4) Cost of Replacement Power to compensate for lost MW during 

construction shutdown period, and 5) Cost of Replacement Power for lost MW Capacity 

due to the derating of DCPP caused by the cooling system reconfiguration. A summary 

of these costs and a high level description of the basis for each of these estimates follows:
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Capital Project Cost $2,689,000,000* 

Decommissioning Cost $67,000,000* 

Operation and Maintenance Cost $7,400,000/Year* 

Replacement Power – Lost During Construction $1,806,000,000* 

Replacement Power – Loss in Net Plant Output $31,600,000/Year*

*2008 Dollars Excluding Escalation and AFUDC

Table 10: Cost Estimate Summary 

Unit prices used in determining capital project costs are derived using PG&E capital 

projects guidelines, manufacturer/vendor input, recent actual costs from other major 

capital projects at DCPP and input from the engineering, operations, project management 

and the work planning departments, as well as estimating judgment. 

2. Capital Project Cost: $2,689 Million 

This cost is based on the conceptual design prepared by Enercon Services and described 

in this report (Reference Capital Project Cost Estimate Details Appendix A-11). The 

estimate includes permitting, engineering, procurement and installation of the new system 

and re-design of existing systems to accommodate the new system. Construction cost 

includes relocation of the plant infrastructure to accommodate the new equipment. 

Reconstruction of displaced plant facilities onsite would be limited to the existing 

developed footprint at DCPP. Not all of the facilities which would be displaced can be 

fully relocated onto the existing DCPP footprint. Allowances have been included for 

reconstruction of those facilities at an offsite location. Equipment manufacturers have 

provided budgetary proposals based on the conceptual design and are incorporated into 

the cost estimate including applicable taxes. Based on the size of this project, its 

manpower requirements and recent DCPP experience, travel through the town of Avila 

Beach would be restricted to a limited number of ‘trips’ through the community. This 

restriction would require DCPP to provide offsite parking, bussing (transportation to and 

from the facility for approximately 3,000 craft personnel), as well as pay for the 

associated travel time. Maintenance or repairs to public roadways outside of DCPP are 

not included in this cost estimate. As safety and security are always a foremost concern 

at DCPP, the cost of maintaining and ensuring a safe and secure facility are included in 

the construction costs. 

No allowances have been made for escalation, project financing costs and/or foreign 

currency exchange rate fluctuations. All costs are in present day (2008 US Dollars) and 

include indirect cost and corporate overhead exclusive of financing costs (Accumulated 

Funds Used During Construction - AFUDC). AFUDC is an estimate of PG&E’s cost of 

capital invested in a project during construction, and is applied to all the Utility’s capital 

orders or projects that have a construction period greater than 30 days. AFUDC is 
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March 2009 

applied to a project’s total direct cost, applicable taxes, and capital administrative & 

general (A&G). AFUDC is accrued from the first month that costs are first charged to a 

project and continues until the month the project is declared operational. AFUDC is 

included in a project’s overall cost and recovered from the ratepayers. Based on the 

proposed schedule, it is estimated that the total capital project costs presented would 

double if it were to include AFUDC and escalation. Demolition cost includes an 

allowance for fluorescent light fixture and ballast disposal, asbestos disposal as contained 

in some building systems, and lead abatement at the existing security firing range. No 

other allowances have been made for hazardous, contaminated or environmentally 

adverse material abatement of any kind. 

3. Decommissioning Cost: $67 Million 

The project would have a significant impact on the overall decommissioning cost at the 

end of the useful life of DCPP. Though the current developed footprint would not be 

expanded, the areas currently used for parking would be replaced by structures. The new 

construction put in place would eventually be removed as part of the station’s 

decommissioning process. The cost of this added removal scope must be included in the 

decommissioning fund. The cost estimate for the decommissioning is based on analysis 

of the current estimate of the cost to decommission DCPP as a percentage of the 

escalated cost to build the plant, and is adjusted to a lower value to reflect the noncontaminated nature of the new systems (decommissioning at 2.5% of install costs). 

4. Operation and Maintenance Cost: $7.4 Million Annually 

The operation and maintenance cost of maintaining the mechanical draft cooling towers 

is based on general vendor recommendations. The costs which have been provided 

include daily, weekly, monthly, quarterly, semi-annual and annual inspections and 

maintenance. Labor, material and chemicals are also included. Allowances have been 

included for the cost of increased maintenance to electrical equipment due to salt drift 

and for the cost of travel between onsite and offsite facilities. These costs would be in 

addition to costs currently incurred for operation and maintenance of the existing cooling 

system. Combined intake pump and electrical systems, cooling systems piping, concrete 

conduit, and main condenser operation and maintenance cost are assumed to be roughly 

equivalent (Reference Appendix A-11 Project Cost Estimates Page-2 Annual Increase to 

Station Operation & Maintenance Cost). 

5. Replacement Power – Lost MW During Construction: $1,806 Million 

In order to safely execute this project, both nuclear units would be shut down when 

construction activities expose main mechanical or electrical systems or jeopardize any 

nuclear safety related systems. During this shutdown period, power must be purchased to 

meet the demand of the PG&E service area. This period is expected to last a minimum of 

17 months (517 days). The formula for calculating replacement power is based on an 

estimate of each unit’s annual output priced using PG&E’s current (2008) long term 

power procurement forecasts of $70 per MWHr, and a Plant Capacity Factor of 90%. 
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Construction Replacement Power Cost Estimate Calculation: 

$70/MW * 1,155 MW/Hr * 24 Hr/Day * 517 Days * 2 (Units) * 0.9 (Capacity Factor) 

= $1,805,736,240 (say $1,806,000,000) 

6. Replacement Power – Lost MW due to Derated Capacity plus Additional 

Auxiliary Power: $31.6 Million Annually 

After installation, the cooling towers would result in decrease in net plant output due to a 

decrease in generator output, and an increase in required plant auxiliary power. PG&E 

would meet service territory demand by purchasing an equal quantity of replacement 

power ongoing. The cost of replacement power is calculated using an average of $70 per 

MWHr based conservatively low on PG&E’s 2008 replacement energy costs. Plant 

Capacity Factor of 0.9 assumes a one unit 25-day refueling outage during any given year. 

 Average Derate Annual Replacement Power Cost Estimate Calculation: 

$70/MW * 451,180 MW-Hrs/Yr [Ref. Table 3] 

= $31,582,600 (say $31,600,000) 

. 
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Description Total Price 

2 Units 

Mechanical Equipment: 

Cooling Towers $80,000,000 

Condenser Waterbox/Tubesheets/Tubes $62,780,000 

Circulating Water Pumps $46,400,000 

Other Pumps $4,900,000 

Valves (96”, 78”, & 36”) $3,999,000 

Electrical Equipment: 

500 kV/13.8 kV Transformers $8,000,000 

Other Transformers $3,420,000 

Cooling tower electrical building. Foundation not 

included $2,870,000 

500 kV substation package for cooling tower power 

supply (excluding transformers) $12,000,000 

Other: 

Dechlorination System $500,000 

Paralined Steel Piping $18,222,000 

Fiberglass Reinforced Plastic Piping $1,072,000 

Instrumentation and Controls $4,254,000 

Sewage Treatment Plant $300,000 

Total Major Equipment Procurement Cost $248,189,000 

 *Excludes shipping, taxes, import fees, etc.

Table 11: Major Equipment Procurement Cost* 
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Figure 17 – Conceptual Installation and Plume – Perspective From Ocean 
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March 2009 

Acronyms and Abbreviations

A&G Administrative & General 

AFUDC Accumulated Funds Used During Construction 

APCD Air Pollution Control District 

ASW Auxiliary Saltwater 

BOD Biological Oxygen Demand 

C Celsius 

CARB California Air Resource Board 

CCW Component Cooling Water 

CDP Coastal Development Permit 

CDR Condensate Regeneration System 

CFR Code of Federal Regulations 

Cu Copper 

CWP Circulating Water Pump 

CWT Circulating Water Tunnel 

CY Cubic Yard 

DCPP Diablo Canyon Power Plant 

EDG Emergency Diesel Generator 

ELGs Effluent Limit Guidelines 

EPA Environmental Protection Agency 

F Fahrenheit 

FHB Fuel Handling Building 

FSAR Final Safety Analysis Report 

GHG Green House Gas 

GPD Gallons per Day 

GPM Gallons per Minute 

HEI Heat Exchange Institute 

HMI Human Machine Interface 

hp Horsepower 

HX Heat Exchanger 

I&C Instrumentation & Control 

I&E Impingement and Entrainment 

I/O Input/Output 

ISO Independent System Operator 

ISFSI Independent Spent Fuel Storage Installation 

kW Kilowatt 

kV Kilovolt 

kVA Kilovolt-Amps 

LAR License Amendment Request 

LRW Liquid Radioactive Waste 

MGD Million Gallons per Day 

mg/L Milligrams per Liter (parts per million) 

MTCS Main Turbine Control System 

MVA Million Volt-Amps 

MWHr Megawatt Hour 
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MWTS Makeup Water Treatment System 

NEI Nuclear Energy Institute 

NEPA National Environmental Policy Act 

NPDES National Pollutant Discharge Elimination System 

NRC Nuclear Regulatory Commission 

NWS National Weather Service 

OE Operating Experience 

OTC Once-Through Cooling 

PA Protected Area (inside security perimeter) 

PM10 Particulate Matter 10μm and smaller 

PDN Plant Data Network 

PPC Plant Process Computer 

PTO Permit to Operate 

PSIG Pounds per Square Inch Gauge 

Q Quarter 

RO Reverse Osmosis 

RWQCB Regional Water Quality Control Board 

SACTI Seasonal/Annual Cooling Tower Impact 

SCW Service Cooling Water 

SER Safety Evaluation Report 

SGBD Steam Generator Blowdown 

SLO San Luis Obispo 

SONGS San Onofre Nuclear Generating Station 

SSPS Solid State Protective System 

SWRCB State Water Resources Control Board 

SWRO Seawater Reverse Osmosis 

TBS Turbine Building Sump 

TDH Total Differential Head 

TDS Total Dissolved Solids 

ug/L Micrograms per Liter (parts per billion) 

UPS Uninterruptable Power System 

UV Ultra Violet 

WB Wet Bulb 

ZLD Zero Liquid Discharge