
                                       
                                  MEMORANDUM

Tetra Tech, Inc.
10306 Eaton Place, Suite 340
Fairfax, VA 22030
phone	703-385-6000

TO:			Paul Shriner and Jan Matuszko, USEPA
FROM:		John Sunda (SAIC) and Kelly Meadows
DATE: 		March 8, 2010

SUBJECT:		Estimation of Net Difference in Capital and O&M Costs for Once-through Versus Closed-Cycle Cooling for New Generating Units at Existing Power Plants and for Repowering of Existing Generating Units

EPA requested that Tetra Tech and SAIC estimate engineering costs associated with construction of cooling water systems for new generating units and for repowered generating units as a way to compare these costs against those for retrofitting intake technologies or flow reduction requirements at existing generating units.

The following cost analysis provides an estimate of the net difference in capital and operations and maintenance (O&M) costs between the cooling system options of flow reduction using closed-cycle cooling with mechanical draft cooling towers versus once-through cooling.  Separate cost estimates are provided for new and repowered generating units as well as generating with different thermal efficiencies.

Introduction

The construction of new generating units and repowering of existing units at existing power plants is a common practice employed by electric generators to meet one or more of the following goals: to increase plant capacity; to increase plant efficiency; to reduce operating costs, to extend plant life, to improve plant reliability; and to reduce emission of pollutants.  There are numerous financial, engineering, and regulatory benefits to adding to or rehabilitating generating capacity at existing sites compared to building new units at a new site.  For example, a new or repowered unit may increase the total capacity, allowing the plant to better meet the demand for power; alternatively, a new or repowered unit may replace (or make obsolete) an older generating unit that was no longer cost-effective to operate, creating a more competitive portfolio for the utility.  Additionally, projects at existing plants (including repowering projects) can take advantage of existing infrastructure and support services, while the construction of new generating units offers significant flexibility in the unit's design and location.

As detailed below, the capital costs for either a once-through or a closed-cycle cooling system at new generating units are relatively similar: for each type of generating unit, once-through systems are approximately 15% more expensive.  For repowered units, capital costs for closed-cycle systems are nearly twice as high for an "easy" difficulty retrofit and approximately three times more costly for an "average" retrofit.  For all generating units (new or repowered), O&M costs are approximately twice as high for closed-cycle systems.

Definitions

For the purposes of this analysis, the term "new units" refers to generating units that do not replace the generating capacity of existing generating units and will require their own cooling system that is mostly independent of the cooling system and intakes for the existing generating units.  The once-through cooling option for new units is assumed to require a new intake and discharge structure either adjacent to the existing intake or in a new location.  The closed-cycle cooling option for new units is also assumed to be completely independent of the existing plant cooling systems, with the exceptions of make-up water which may be withdrawn from the existing cooling system and tower blowdown which may be combined with an existing plant discharge.

For the purposes of this analysis, the term "repowered units" refers to full repowering projects where all (or a large portion) of the major components of an existing generating system such as boilers, steam turbines, and condensers are replaced or upgraded.  The repowered generating system is assumed to be located and sized such that the repowered unit(s) will continue to use the existing once-through cooling water intake, intake pumps, and discharge system.  It is assumed that the water withdrawal flow rate(s) and heat discharge rate(s) would not increase.  In fact, since repowered systems are almost always more efficient, more power can be generated even though the cooling water capacity has not changed.  Table 1 below shows the equivalent increase in generating capacity for a repowering project if an average existing 500 MW conventional steam cycle plant with an efficiency of about 32% (heat rate = 10,800 BTU/Kwh) is replaced with a newer, more efficient steam plant that is sized to reject the same amount of waste heat (i.e., no changes to cooling water flow rate and condenser temperature rise [range]).

Table 1. Equivalent Generation Capacities for Steam Power Plants with Similar Heat Rejection Rates and Equal Cooling Water Flows

                               Plant Efficiency
                           Equivalent Capacity (MW)
                                Increase Factor
Older Existing Coal
                                      32%
                                      500
                                      1.0
Sub-Critical Fossil Fuel
                                     39.2%
                                      653
                                      1.3
Ultra-Critical Fossil Fuel
                                     45.5%
                                      888
                                      1.8
Combined Cycle
                                     56.9%
                                     1451
                                      2.9

General Design and Cost Assumptions

Net O&M and capital costs are estimated on a per MW generating capacity basis so that these cost estimates can be applied to generating units of any size.  For repowered units, since the assumptions are that the existing intake will be used for the once-though option, the costs apply only to situations where the new condenser flow rate is equal to or less than the existing condenser flow rate.  Thus, the repowered units will have an increase in power generating capacity similar to the ratios shown in Table 1.

Costs are derived using estimated cooling water flow rates and corresponding costs for 500 MW generating units representing three different available boiler designs.  Table 2 presents the generating unit efficiency and design cooling system flow assumptions.  The heat rate and efficiency values for ultra-critical fossil fuel and combined cycle represent estimates of the current state-of-the-art capabilities for these types of generating systems.

Table 2. Generating Unit Design Assumptions

                           Sub-Critical Fossil Fuel
                          Ultra-Critical Fossil Fuel 
                                Combined Cycle
Capacity (MW)
                                      500
                                      500
                                      500
Heat Rate (BTU/KWh)
                                     8,700
                                     7,500
                                     6,000
Plant Efficiency (%)
                                     39.2
                                     45.5
                                     56.9
Range ([o]F)
                                      20
                                      15
                                      20
                                      15
                                      20
                                      15
Cooling Water Flow (gpm/MW)
                                      440
                                      590
                                      320
                                      430
                                      200
                                      270
Cooling Water Flow (gpm)
                                    220,000
                                    295,000
                                    160,000
                                    215,000
                                    100,000
                                    135,000

The design assumptions in Table 2 are used for both the new unit option and the repowering option.  It is assumed that the cooling (circulating) water flow rate will be the same for once-through and closed-cycle cooling options for each generating unit.  Costs are estimated for two different condenser temperature rise (range) values of 15[o]F and 20[o]F, since cooling water per MW will be different for different range values.  These two values were selected because they are typical for values used at existing plants.  The ratios between heat rejection and cooling water flow (shown in Table 1), however, do not change as long as the range is the same for the new repowered and old generating units.  The flow rate estimates in Table 2 are based on the assumed heat rates and the assumption that 90% of the heat not converted to electric power ends up being rejected from the system through the cooling water. 

Repowering Scenarios

Once-Through Option

The repowering scenarios are assumed to be a full repowering where all of the major components of the generating system such as boilers, steam turbines, and condensers are replaced or upgraded.  For the once-through option, it is assumed that the existing shoreline intake pump well and cooling water piping are retained for the new system.  

Cost assumptions for the once-through cooling system include:

   * System will use existing intake pumps and piping;
   * Pumping head is 35 ft;
   * Intake will be upgraded to modified Ristroph screens with a 0.5 fps through-screen velocity, requiring an expansion of the intake;
   * Intake upgrade costs are based on a cost module for a new, larger intake structure;
   * O&M costs are based on coarse mesh modified Ristroph screens with the average intake flow equal to 75% of design flow;
   * Intake water depth is assumed to be 18 ft and well depth used for cost estimates is 50 ft;
   * Existing circulating pumps will be upgraded to variable speed using VFDs, based on a unit cost of $15/gpm applied to the cooling water flow.

The major capital cost components for the once-through option are the upgrades of the intake needed to meet impingement requirements, which include the intake and screen upgrade and the upgrade of pump drives with VFDs.  A review of the intake upgrade cost estimates for different flows showed that they were not linear, while most other cost components in this analysis (including the cooling tower costs) are in fact linear.  To avoid the skewed results for net costs that would result from mixing linear cooling tower costs and non-linear intake modification costs, capital costs were derived for the median flow for the ultra-critical fossil fuel plant for Cost Module 3 and then converted to unit costs in dollars/gpm.  These unit costs were then applied to the flows for all three generating unit types.

The major O&M cost components for the once-through option are the intake technology O&M and the pump energy.  The intake technology O&M is based on modified Ristroph traveling screens with a through-screen velocity of 0.5 fps.  The O&M costs were linear.

Closed-Cycle Option

The required retrofit components for the closed-cycle option are similar to those required for cooling tower retrofits at existing generating units that are not modified or repowered.  However, in some respects, demolition and construction activities associated with unit repowering should make the retrofit easier and somewhat less costly compared to retrofitting an unmodified unit.  In addition, there should be no difference between cooling system options for the construction downtime associated with the repowering, as the construction of either cooling system could easily be completed during the scheduled construction downtime.

Recirculating tower option costs were estimated for two retrofit conditions using cost estimate factors derived from the EPRI Tower Calculation Worksheet (EPRI 2007a).  One cost estimate uses the EPRI cooling tower retrofit costs for the "easy" difficulty cooling tower installation option, which represents situations where there is suitable space nearby for the cooling tower and that the repower project construction is extensive enough such that many of the difficulties encountered in retrofitting cooling towers to a mostly unaltered existing generating unit can readily be addressed through design modifications of the repowered units.  This would be more applicable to major repowering projects where a substantial portion of the existing generating unit is demolished and replaced with an entirely new system.  The other cost estimate uses the EPRI cooling tower retrofit costs for the "average" difficulty cooling tower installation, which represents more difficult circumstances, such as limited space onsite or the proximity of residential areas.  Both of these cost items include all of the typical capital cost components of a cooling tower retrofit, including cooling towers, pumps, piping, make-up water and blowdown systems.  

The factors cited by EPRI (EPRI 2007b) that affect the selection of cooling tower retrofit difficulty include:

   * The need to make modifications to the condensers;
   * The distance between the tower and generating unit;
   * Steps necessary to prepare the site such as demolishing buildings or structures;
   * Elevation of tower site, e.g., too low site elevation may require grading to raise elevation or extra pumps for return flow;
   * Presence of underground, surface and overhead interferences such as utilities, roadways, and overhead transmission lines that may conflict with the placement of the towers, water pipes, and pump wells;
   * Difficulty related to tie-in and ability to use existing intake and discharge structures for make-up and blowdown;
   * Proximity of the location selected for circulating pumps and the availability of power;
   * Presence of unfavorable soil conditions or contamination.

Since this option assumes that major modifications, if not a complete rebuild, will be performed on the generating unit as well as portions of the cooling system, it is reasonable to assume that some of these difficulties will be dealt with regardless of the cooling option selected and that many may be at least partially mitigated in the repowered system design.  For this reason, only the "easy" and "average" difficulty cost options are included in these repower cooling tower options.

The following assumptions were used for the closed-cycle option:

   * Retrofit capital costs are based on EPRI capital cost factor of $160/gpm for an "easy" retrofit and $249/gpm for an "average" retrofit;
   * Cooling tower pump energy requirements are based on a total pumping head of 38 to 40 ft;
   * Cooling tower fan energy requirements are based on tower cells sized to handle 12,000 gpm per cell with 200 Hp fans in each cell;
   * Cooling tower O&M is based on the EPRI cost estimate plus added costs for optimized operation at a higher cycle of concentration (COC) than is typical for existing power plants with cooling towers.  The cost factor used was $2.01/gpm of recirculating flow.

New Generating Unit Scenarios

New generating units are assumed to require their own cooling water system that is mostly independent of the existing cooling water system.  While the site layout may impose certain restrictions, the flexibility inherent in new construction should allow for more optimal placement of generating units, cooling towers, piping, and intakes, at least between the cooling system options, than would be available for repowering of existing units.  It is assumed that cooling water piping costs will be the same for each cooling option, since the cooling flow will be the same and similar sized pipes would be used, and thus the cost differences will be dependent mostly on the required distances for each option.  Without knowledge of site-specific conditions, it is not possible to determine which option would require greater lengths of piping.  

Once-Through Option

For the once-through option, a new intake structure and traveling screens must be constructed along with the pump wells.  These costs are based on Cost Module 3.  While this module is intended to estimate the cost for adding a new larger intake in front of an existing intake, is assumed to be reasonably similar to the cost for construction a portion of a new intake.  An additional cost is added to account for the deeper pump wells needed for the once-through option (as opposed to a closed-cycle pump well, which can be shallower).  Since both pump well and intake screen structures should be similar in relative size and cost with respect to concrete requirements and equipment requirements (pump shafts versus added screen height), the added pump well depth cost is assumed to be similar in magnitude to the difference in cost between the cost for Module 3 with a 50 ft screen well versus Module 3 with a 25 ft screen well.  This is based on the assumption that the concrete and equipment costs for the added depth are comparable for the screen channel walls and added screening equipment versus the pump well walls and pump shaft.

 The assumptions for the once-through option include:

   * Pumping head is 35 ft;
   * Cost for intake screens, screen structure and extra pump well depth are $98/gpm flow. This value is based on costs for Module 3 with a 50 ft screen well using a flow of 160,000 gpm plus difference between Module 3 costs for 25 ft and 50 ft screen wells;

Closed-Cycle Option

It is assumed that the cooling tower option will not require a new intake structure, since make-up can often be taken from the existing plant cooling water intake system.  As such, the cooling tower component costs will be limited to the cooling towers and basins, with some added costs for make-up and blowdown pumping and piping.  Since these flows are relatively low, the make-up and blowdown pumping and piping costs are a relatively small component but are included.  The cooling tower capital costs included in this analysis are limited to these components because both systems will require similar pump and piping costs.

Capital costs for the pumping equipment are assumed to be the same as those for the once-through option.  The pump well component costs are also assumed to be equal, except that the surface water intake pump well structure for the once-through option must be deeper to allow for water level fluctuations and prevent equipment damage from flood conditions. 

The assumptions for the closed-cycle option include:

   * Cost of cooling tower is assumed to be $80/gpm. This cost is derived from the estimated median total cost for the towers and basins based on cost estimates presented in the report "California's Coastal Power Plants: Alternative Cooling System Analysis" (Tetra Tech 2008).  These costs include the 25% indirect and 25% contingency factors used in this report.  Report costs are based on design and build estimates submitted by cooling tower vendors plus engineering estimates for the concrete basins;
   * Capital cost of makeup water pumps and piping is assumed to be 5% of cooling tower costs;
   * Pump energy requirement is based on total pumping head from EPRI worksheet (38 to 40 ft);
   * Fan energy requirement is based on tower cells sized for 12,000 gpm per cell with 200 Hp fans;
   * Cooling tower O&M is based on the EPRI cost estimate plus added costs for optimized operation at a higher COC than is typical for existing power plants with cooling towers.  The cost factor used was $2.01/gpm of recirculating flow.

Turbine Efficiency Penalty

It is expected that the turbine efficiency penalty as a percent of total power generation will be lower for newer, more efficient generating units.  The estimates for the turbine efficiency penalty presented here use the current EPA estimates for existing plants of 1.5% for non-nuclear and 2.5% for nuclear plants as the starting point.  For newer, more efficient generating units, these values are adjusted using assumed high pressure (HP) steam turbine inlet pressures.  The assumption is that the energy available is a function of the difference between the high pressure and low pressure sides of the steam turbine and that the energy loss in MW associated with a given increase in the turbine exhaust backpressure is somewhat constant, all else being equal.  Thus, the percent of energy loss due to a given change in turbine backpressure should decrease and be indirectly proportional to the increase in the HP steam inlet pressure.  While the energy available is also a function of the inlet steam temperature and steam reheat steps, these values tend to be higher as well for the newer generating systems. 

It is also assumed that for new and repowered units, either new or refurbished turbines and condensers with improved optimal designs will be utilized and that they will result in improved equipment efficiency.  This improvement is assumed to result in a 10% reduction in the energy penalty over equivalent existing designs.  Table 3 shows the estimated existing plant energy penalty adjustments based on proportional differences in the assumed HP turbine inlet pressures.  For combined cycle, the adjustment is based on the assumption that the steam component penalty would be similar to that for an existing non-nuclear plant but is responsible for only 1/3 of total generation.  Table 4 presents the estimated energy penalty for repowered and new generating units.  While the energy penalties for non-optimized repowered units are also shown in Table 4, it is reasonable to assume that in most cases optimization of condensers and turbines will occur.

Table 3. Assumed Values and Penalties for Existing Plants
                                  Plant Type
                           Assumed Plant Efficiency
                    Assumed HP Turbine Inlet Pressure (psi)
            Penalty Without Optimizing Turbine and Condenser Design
Nuclear
                                      33%
                                      800
                                     2.5%
Non-nuclear (Old and New)
                                      34%
                                     2400
                                     1.5%
Non-nuclear 39%
                                      39%
                                     3600
                                     1.0%
Non-nuclear 45%
                                      45%
                                     4500
                                     0.80%
Combined Cycle[1]
                                      57%
                                     1800
                                     0.67%
1 Assumes HSRG produces 33% of power.

Table 4. Estimate New and Repowered Unit Turbine Efficiency Energy Penalty
                                  Plant Type
                       Assumed Plant Thermal Efficiency
                    Turbine Efficiency Penalty  -  Repower
              Turbine Efficiency Penalty  -  Repower Optimized[1]
                     Turbine Efficiency Penalty  -  New[1]
Nuclear
                                      33%
                                     2.5%
                                     2.25%
                                     2.25%
Non-nuclear (Old and New)
                                      34%
                                     1.5%
                                     1.35%
                                     1.35%
Non-nuclear 39%
                                      39%
                                     1.0%
                                     0.90%
                                     0.90%
Non-nuclear 45%
                                      45%
                                     0.80%
                                     0.72%
                                     0.72%
Combined Cycle[2]
                                      57%
                                     0.67%
                                     0.60%
                                     0.60%
1 Assume turbine and condenser optimization
2 Assumes HSRG produces 33% of power

Estimated Costs

Tables 5, 6, and 7 present a summary of the estimated Capital and O&M costs in dollars (and MW) per MW generating capacity representing the difference in costs between the two cooling system options for the three different fuel-type 500 MW plants shown in Table 2.  Table 5 presents the estimates for adding a new generating unit to an existing power plant and Tables 6 and 7 present the estimates for repowering existing generating units for "easy" and "average" difficulty cooling tower retrofits, respectively.  The tables show the total costs and differences in costs for the components included in this analysis, but do not necessarily include items that were assumed to be equal in value between the cooling options.  The unit costs per MW were derived by dividing the cost difference by the generating capacity.  The costs in columns 3 through 6 were derived using estimated flow rates for a condenser temperature rise (range) of 20[o]F.  To obtain the unit cost estimates for a range of 15[o]F shown in the last column, the 20[o]F range costs were adjusted based on the differences in the estimated condenser flow rates.  

Costs are in 2009 dollars, with intake module costs adjusted for inflation using the February 2009 ENR CCI index of 8533.  O&M costs for energy in dollars and the resulting total were derived using an assumed value of $50/MWh and are presented for comparative purposes.  Where possible, economic analyses should use the energy values shown in MW and apply the predicted energy cost per MW for the specific application.

References

Tetra Tech. California's Coastal Power Plants: Alternative Cooling System Analysis. February 2008.

EPRI. Tower Calculation Worksheet. 2007.

EPRI. Instructions for Retrofit Cost Analyses. 2007

 
 
 
