
                                  MEMORANDUM

Tetra Tech, Inc.
10306 Eaton Place, Suite 340
Fairfax, VA 22030
phone	703-385-6000
fax	703-385-6007

DATE: 		March 9, 2011

TO:			Paul Shriner, EPA
	
FROM:		John Sunda, SAIC and Kelly Meadows, Tetra Tech

SUBJECT:	Repowering and 316(b)

Power plant repowering is simply the "refurbishment of a plant by replacement (or upgrade) of the combustion technology with a new combustion technology, usually resulting in better performance and greater capacity" (DOE 2009).  As power plants age, the generating units become less efficient and prone to higher operations and maintenance (O&M) costs.  The additional maintenance requirements of older combustion equipment may also result in more frequent maintenance outages, reducing the equipment reliability.  These factors make their operation less economically attractive when compared to newer, more efficient processes and equipment.  In addition, new restrictions on environmental emissions create requirements that older technologies may not be capable of meeting without equipment modifications or installation of expensive abatement technologies.  In some cases, the environmental emission restrictions may result in the need to derate (reduce power output), especially at times of peak power demand or high source-water temperatures.  The derated capacity must be made up by adding capacity or using other, often less cost-efficient generating systems.    

As aging plants become less cost-efficient than the newer systems, over time they are operated less frequently, resulting in progressively lower capacity utilization rates, and may eventually be retired.  At the same time, the demand for increased power generating capacity throughout the US is constantly increasing.  Power companies generally have two alternatives for dealing with these problems:  1) construct new greenfield generating plants or add new generating units at an existing facility to replace the capacity of older generating systems that are eventually retired or 2) refurbish (repower) existing generating facilities.  The strategies employed by power companies often involve a mix of both options and are driven mostly by economic considerations.  

This memo discusses repowering of existing combustion-based generating plants using combustion-based systems and does not address the addition of new capacity.  

Repowering is an attractive alternative because it can simultaneously address issues regarding load growth, environmental compliance and technological obsolescence.  Improvements that can be achieved through repowering include some or all of the following possibilities (Stenzel et al 2009):

 It may be the least-cost option for increasing generation capacity
 It can minimize capital cost expenditures 
 It can reduce overall system fuel usage and/or costs
 It can reduce O&M costs
 It can reduce emissions and other discharges
 It can reduce water usage per KW generated

At any given facility, repowering projects can involve existing units still in operation or generating units that have been retired and inactive for a number of years.  Repowering projects often help meet increasing load demand by increasing the power output of an existing plant.  The increased output may result from both the use of more efficient equipment and combustion processes, as well as the addition of combustion capacity and generating equipment.  In some cases, repowering does not result in an increase in the generating capacity.  The goals of such projects often include reducing costs, reducing emissions, improving reliability, or changing the fuel used or allowing for more flexibility in the type of fuel used.

Repowering an existing facility has numerous advantages over building a greenfield facility to meet electricity demand or replace the capacity of inefficient or retired existing generating units.  Repowering projects avoid some of the problems associated with greenfield projects and may offer the following advantages:

 Avoid the difficulty and public resistance to the siting of new transmission lines associated with new facilities
 Avoid the difficulties and public resistance to the siting of new plant facilities
 Avoid the difficulties of obtaining environmental permits for new facilities
 Can reduce investment costs by utilizing existing equipment, structures, and land
 Can utilize existing transmission and steam distribution equipment
 Can utilize existing utility connections and fuel delivery systems
 Can utilize existing highway and rail access
 Can utilize existing trained staff
 Can utilize existing cooling water intake and discharge equipment, structures, and permitted water withdrawal capacity
   
Fuel efficiency is of the utmost importance at power plants.  Even small increases in plant efficiency of 1% to 2% can result in substantial financial benefits.  For example, a 1,000 MW coal-fired plant with an initial thermal efficiency of 36% LHV (lower heating value) and a fuel cost of $2 per Million BTU will expend over $150 million annually in fuel costs alone.  If the plant efficiency were increased by just 1% to 37%, the annual fuel savings would be approximately $4 million.  Thus, historically, power plants have been willing to invest substantial quantities of money for even small increases in plant efficiency.  Repowering can provide for substantially larger increases in efficiency as shown in Table 1.
     
Repowering Options

Many existing facilities have multiple generating units of various ages and many of these units may be infrequently used or retired.  Increasingly, facilities are evaluating the possibility of repowering existing generating units.  These generating units may have different designs, ages, equipment conditions, and fuel types.  Repowering may involve the replacement of the entire system, the replacement of a portion of the system, or the addition of new combustion/generating equipment that is incorporated into the existing system.  In many cases, especially if the steam turbines are in relatively good condition, the existing steam turbine equipment remains in use and additional non-steam generation capacity is added.  In such a case, the cooling water design flow requirement would remain the same.  As noted above, there is generally a greater incentive to repower or replace the older steam units that tend to cost more and generate more environmental emissions per KWh generated.

Many of the repowering technologies involve the use of combustion turbines either alone or, more often, in conjunction with steam cycle power generation.  The combination of combustion turbines with steam cycle power generation, also known as combined cycle, generally results in a much more efficient system than the use of either alone.  Combined cycle generating systems offer greater flexibility in their application because they can be started up and shut down more rapidly than steam generation systems and thus can function more efficiently as intermediate load and peaking load facilities in addition to base load applications.

In order to operate reliably, the high pressure combusted gas stream that powers the combustion turbines must be relatively free of ash and particulates to prevent problems associated with deposition and erosion from affecting the turbine blades.  Liquid and gaseous fuels typically generate fewer quantities of ash or particulates and thus are the preferred fuels used to power combustion turbines.  The exceptions are solid fuel systems that either convert the solid fuel to a combustible gas that can then be used as fuel in combustion turbines, or that combust the solid fuel under pressure and then remove the ash and particulates prior to passing the pressurized combustion gases through the gas turbines.  Some turbines are designed to be more compatible with slightly elevated ash and particulate levels.

Some repowering projects may involve the replacement of existing generating equipment that utilizes steam as a prime mover with generating equipment that does not use steam (e.g., combustion turbines).  Generating units that use combustion turbines alone are most often used to provide peaking power because they can be rapidly started up and shut down, but are generally not as efficient as new steam power and combined cycle systems.  Wherever existing steam generating capacity is replaced with combustion generating capacity, the cooling water requirement will be reduced.  This option, however, is not discussed in detail here.

The various types of repowering options that can be applied at existing steam cycle generating systems are described below.  These are divided into two main groups: combustion turbine-based systems which generally involve the use of gas or liquid fuel to power the combustion turbines; and solid fuel-based systems which use coal or other solid fuels to power the system.

Combustion Turbine-Based Repowering Options

The following repowering options use combustion turbines and combined cycle technologies that may replace the existing generating system, provide supplemental energy to an existing system, or be integrated into an existing system with replacement of portions of the existing equipment.  Each option results in a system that is more efficient and often has a higher total power output than the existing system.  All of these systems use gas or liquid fuels to power the added combustion turbine technology.  In systems where the existing boiler remains in operation, the existing boiler may continue to use the same fuel type as before.  Otherwise, if the existing system does not use natural gas or oil, then the repowering may involve a complete conversion of the type of fuel used.

Site Repowering or Full Repowering involves the demolition of the existing generating units (except for possibly the cooling water system, switchyard, and other ancillary systems and building structures), followed by the construction of a new combined-cycle or other type of plant in its place.  In some cases, if space allows, the old system may be kept in operation while a portion or all of the new system is constructed nearby.  Site repowering is commonly used at very old plants where the boilers and steam turbines are at the end of their useful lives.  It is considered one of the simplest ways of repowering an existing plant.

Combined Cycle Repowering (CCR) involves the replacement of the existing boiler by a combustion turbine and a heat recovery steam generator (HRSG).  The HRSG generates steam using heat from the combustion turbine exhaust gases.  Steam from the HRSG then powers the existing steam turbines.  The old boiler and furnace may be demolished first or the new combustion turbine and HRSG power block may be constructed on an adjacent location with the HRSG steam replacing the existing boiler as the steam source only after construction is completed.  Combined cycle repowering is the most common type of repowering currently being implemented in the U.S.  

Hot Windbox Repowering (HWBR), also known as Topping, involves the conversion of a steam cycle unit to combined-cycle where the existing boiler remains intact and a gas turbine is added to the system such that exhaust hot gases from the gas turbine replace all or a portion of the combustion air entering the existing conventional steam boiler-turbine unit.  The hot exhaust from the gas turbine is used as preheated combustion air in the existing boiler.  Thus, the additional fuel used in the gas turbine will offset some of the fuel requirement for the existing boiler, providing an increase in system efficiency associated with a combined cycle system while maintaining the existing boiler steam output conditions at which the existing steam turbines are designed to operate most efficiently.  Partly because the combustion now has a lower oxygen content, this type of conversion involves the highest degree of technical complexity of all the combustion turbine-based repowering options.  The added combustion turbine contributes a relatively small amount of the total power to this configuration.  Therefore, the final efficiency of a HWBR unit will be dominated by the efficiency of the larger steam cycle.  For this reason, existing units that already have the capability of being more efficient will be preferred candidates for HWBR.

Feedwater Heater Repowering (FWHR), also known as Boosting, involves the addition of a combustion turbine with the exhaust gas from the combustion turbine being used to heat the boiler feedwater in the existing steam-cycle power plant.  In a conventional steam turbine unit, some of the boiler steam is diverted to heat the boiler feedwater which starts out at the relatively low temperature of the condensed steam in the condensers.  By replacing this diverted steam with another heat source, additional power can be produced by the additional steam sent to the steam turbine-generator.  Also, power generation is augmented by the combustion turbine.  The benefit of additional steam turbine generation occurs only if the design limits of the steam turbine are not exceeded.  The existing feedwater heaters can be retained to allow for conventional operation when the combustion turbine is not needed or out of service.

Supplemental Boiler Repowering (SBLR) involves adding combustion turbines with the exhaust gases being used in an HRSG that provides additional steam to directly supplement the steam supplied by the existing boiler used to power the existing steam turbines.  The economics of this configuration depend greatly on the ability to use the additional steam efficiently in the turbine generator and/or whether the existing boiler has steam generation limitations that result in the steam turbines not being able to operate at their full power capability.
 
Parallel Repowering (PR) involves adding a combustion turbine and an HRSG that supplies steam to the existing steam turbines.  This application is similar to SBLR except that in SBLR the existing boiler remains in operation continuously, while in PR the existing boiler only operates for peak and intermediate loads.  The steam from the existing boiler is added to the steam from the HRSGs at several pressure levels, depending on the condition and capability of the existing steam turbines.

Solid Fuel-Based Repowering Options

Most solid fuels tend have a lower cost than natural gas or liquid fuels such as fuel oil.  Where low cost solid fuels are already in use or are available, repowering with solid fuel-based technology may be selected for the cost advantages.  Solid fuel options tend to have higher up-front capital costs and therefore are more suited to systems requiring a higher capacity factor in order to recover the investment.  Systems that use the newer fluidized bed combustion technology are capable of switching between a variety of solid fuels.  Being able to alternate between different solid fuel types provides the opportunity to utilize lower-cost fuels such as high ash coals and waste materials (e.g., petroleum coke) or to use fuel blends, and allows the flexibility to take advantage of variations in fuel availability and costs over time.  The use of lower-cost solid fuels can offset the higher capital costs and generally lower efficiencies of these solid fuel systems.  The following repowering options are available for use with solid fuels.

Atmospheric Fluidized Bed Combustion Repowering (AFBC) involves replacing the existing boiler with a fluidized bed combustion process.  The new boiler is either designed to match the existing steam turbine or the turbine system is upgraded to a more efficient system.  Fluidized bed systems have the benefit of reducing air pollution emissions exiting the boiler by burning fuel at temperatures low enough to minimize NOX and by reducing SOX through use of sulfur absorbents such as limestone inside the combustion chamber mixed with the fuel as a bed material.

Pressurized Fluidized Bed Combustor Repowering (PFBC) involves replacing an existing boiler with a pressurized fluidized bed combustor to produce steam to drive the existing steam turbine-generator and to generate pressurized hot gases that drive combustion turbines.  Hot gases from combustion turbines are used to generate steam in an HRSG to power existing steam turbines.  This technology, also referred to as first-generation PFBC, uses a "relatively stationary fluidized (bubbling) bed" using relatively low air velocities to fluidize the material.  A boiler tube bundle is immersed in the bed to generate additional steam to power the steam turbines.  Particulate matter is removed from the flue gas using cyclone separators prior to the flue gas entering a gas turbine.  The gas turbines are designed to accept a moderate amounts of particulate matter.  PFBC technology introduces some significant operating complications to the fluidized bed combustion process in that solid fuel, sorbent, and air must be transferred into a pressurized process vessel and ash transferred out.

Pressurized Circulating Fluidized Bed Combustor Repowering (PCFBC) is similar to PFBC and is referred to as the second-generation pressurized fluidized bed combustion process.  PCFBC uses a "circulating fluidized bed" that uses higher air flow volumes to circulate fuel and sorbent in the fluidized bed combustor.  This technology uses a number of efficiency enhancement measures, including the integration of a coal gasifier or carbonizer to produce a fuel gas that is combusted in a separate topping combustor that adds to the flue gas energy from the fluidized bed combustor that powers the gas turbine (DOE 2009).  This technology is still in the development stage.

Gasification Combined Cycle Repowering (GCC), also known as IGCC, involves addition of a solid fuel gasification system, a gas processing system, a combustion turbine, and an HRSG.  This system replaces the existing boiler.  The gasification system converts a solid fuel to a gaseous fuel (syngas) used in the combustion turbine, with the hot exhaust gases generating steam in the HRSG.  Steam is also generated in a heat exchanger in the solid fuel gasification process.  Steam from both the solid fuel gasification process and the HRSG powers the existing steam turbine.  In the gasifier, solid fuel is typically exposed to steam and carefully controlled amounts of air or oxygen under high temperatures and pressures.  Under these conditions, the solid fuel breaks down into a mixture of carbon monoxide, hydrogen and other gaseous compounds.  The gasification process can also produce other products that have commercial value, such as sulfur and an inert slag.

The primary benefit of this technology is that air emissions are substantially reduced.  Also, CO2 removal for sequestration (if required in the future) can be done at lower costs than at conventional coal power plants because the CO2 can be removed under pressure during the syngas processing step.  In addition, combustion turbines which run on syngas can generate more power.  The syngas is a low heat-content gas and gas turbines that are run on low heat-content fuel (BTU/gm) must have more fuel injected in order to reach their operating limits, such as combustion temperature.  The resulting higher power output is due to the fact that there is more mass impinging on the turbine blades, which results in greater energy output from the turbines.  For example, a GE Model 6FA turbine has a power rating of 70 MW using natural gas and a power rating of 90 MW using syngas (GE 2009).

Table 1 presents a summary of some of the attributes of each of the repowering options listed above.  It shows the relative capital investment costs when compared to a full repowering option for a combined cycle system of comparable generating capacity.  It also shows potential increases in capacity and system efficiency and construction outage times where available.

Other Modifications

Repowering can also include replacement and modernization of various components of the power plant.  This can include replacement or upgrade of the existing steam turbines and other options described below:

Steam Turbine Upgrade  --  Replacement or upgrade of existing steam turbines may be necessary to optimize system efficiency and capacity, and to match new design specifications.  In one example, upgrading the turbines alone increased output by 7% (Hong Kong Electric Co. 2000).

Instrumentation and Controls  --  Instrumentation and control systems at older plants can be upgraded and "tuned," such that plant efficiency could be increased by 4% to 7% by allowing the boiler and turbine generator to work at their optimum operational control points (Ferrer and Kishinevsky 2008).

Electrical Systems  --  The use of variable frequency drives for boiler feed and condensate pumps, induced draft fans and forced draft fans can provide precise speed and load control with the potential for increased efficiency of up to 2% at reduced loads (Ferrer and Kishinevsky 2008). Also, modest increases in plant efficiency can be achieved by conducting a study of plant power use and minimizing power use by making improvements such as upgrading HVAC systems.

Other Improvements  --  Other improvements could be made to the power cycle to increase the overall cycle efficiency by as much as 4% to 6% (Ferrer and Kishinevsky 2008).  Such improvements include:

 Minimizing excess air and improving combustion control
 Improving cooling tower performance
 Improving condenser performance by installing on-line condenser cleaning

The individual percent increases in efficiency listed above are not necessarily cumulative.  Opportunities for each will be dependent on the design and condition of each system.

              Table 1.  Summary of Repowering Technology Options
Type
                               Brief Description
                                   Comments
                            Performance and Costs 
                              Increased Capacity
                            Change in Efficiency *
                             Relative Investment**
                              Outage Time Months
Site Repowering or Full Repowering
                Entire existing unit is demolished and replaced
                               Simplest method 
Performance same as new greenfield facility. Can save approximately $106 to $300 per KW compared to Greenfield, excluding land costs.
                                 150% to 200%
                                   Up to 20%
                                     100%
                                       
Combined Cycle Repowering (CCR)
      Replace boiler with combustion turbine and heat recovery generator
                     Most common type of Repowering in US
                       Reduces heat rate by 30% to 40%.
                                 150% to 200%
                                  12% to 17%
                                  70% to 85%
                                   12 to 18
Hot Windbox Repowering 
(HWBR)
Add combustion turbine with exhaust gases replacing all or portion of combustion air source for existing boiler
High degree of technical complexity.  Competitive for larger, newer efficient oil/gas-fired units.
Increase capacity 0% to 25%. Increase efficiency by 10% to 20%. Costs $150 to $250 per KW total repowered capacity.
                                   0% to 25%
                                   3% to 6%
                                  20% to 30%
                                       8
Feedwater Heater Repowering (FWHR)
   Add combustion turbine with exhaust gasses used to heat boiler feedwater
              Useful when additional peaking capacity is needed.
Costs $90 to$110 per KW for smaller fossil steam units to $75 to $80 per KW for larger units.
                                  10% to 30%
                                   2% to 6%
                                  15% to 20%
                                       2
Supplemental Boiler Repowering (SBLR)
Add combustion turbine and HRSG which provides supplemental steam to existing turbines
Useful where existing steam turbines can handle more steam than boilers produce. 
       Benefit dependent on ability to use additional steam efficiently.
                                       
                                       
                                       
                                       2
Atmospheric Fluidized Bed Combustion Repowering  (AFBC)
        Replace existing boiler with a fluidized bed combustion process
Benefits are ability to use a variety of solid fuels and reduced emission of air pollutants 
Plant performance is essentially unchanged except for reduction in air emissions.  Reduced operating costs when using low cost fuels. 
                                      0%
                                      0%
                                       
                                       
Pressurized Fluidized Bed Combustor Repowering (PFBC)
Replace boiler with a pressurized fluidized bed combustor to drive combustion turbines and produce steam for existing turbines
Benefits are ability to use a variety of solid fuels, reduced emission of air pollutants, and increased plant efficiency. Available for units ranging from 80 to 350 MW. 
Has the benefit of increased efficiency of 40% to 45% and potential for up to 50% for advanced 2[nd] generation systems.  The proportion of power coming from the steam:gas turbines is approximately 80%:20%
                                  Up to 100%
                                   Up to 12%
                                 150% to 200%
                                       
Gasification Combined Cycle Repowering (GCC)
Add gasification system, combustion turbine and HRSG to provide steam to existing steam turbines
          Only one repowering demonstration has been performed in US.
Expected efficiencies are in the 40% to 45% range.  Gasification process results in relatively high capital costs, in the range of $1,200 to $2,000 per KW. 
                                     165%
                                   Up to 7%
                                 200% to 300%
                                       
* Numerical difference in efficiency.
** Relative to investment for new combined cycle of same capacity.

      Sources: Stenzel et al; Shahnazari et al 2003. 


Repowering Decision Making

The decision of whether to repower and the selection of a system from the many options available requires an in-depth evaluation of many financial and technical considerations and how these relate to the available repowering options.  Such an evaluation could take the following steps:

   1. Determine the generating system goals, including consideration of the following items and/or other requirements and goals:
   
       Projected generating load schedules and requirements
       Value of needed power and forecasted market price
       Air emissions and discharge reductions

   1. Identify site restrictions to help determine if the existing plant can be repowered to meet the generation goals.  This could include consideration of:
   
       Air emissions and discharge limits
       Transmission requirements and limitations
       Equipment age and condition
       Site access
       Technology option limitations
       Permitting requirements

   1. Identify candidate repowering technologies, including those identified earlier in this document, and perform an initial analysis to help narrow the list down to the most competitive technologies.
   
   2. Develop preliminary technology design and costs for each candidate technology, including operation parameters, and conduct a financial analysis, including consideration of: 

       Projected fuel availability and costs
       Anticipated regulatory changes
       Investment capital costs
       System O&M costs
       Schedules
       Future revenue and return on investment
      
   1. Select the best option based on the results of the analysis.

The analysis of each repowering option must take into consideration many factors, some of which may be based on uncertain projections and assumptions.  As such, general rules-of-thumb and simple engineering analyses generally will not suffice in performing such a complex analysis.  To assist in this decision making process, the Electric Power Research Institute (EPRI) has made available a suite of software tools entitled State-of-the-Art Power Plant (SOAPP(R)).  SOAPP(R) includes numerous software modules, with the two most relevant to repowering being the "SOAPP(R) Repowering Screening Module" and the "SOAPP(R) REPO CC WorkStation."  These software tools are available from EPRI for a fee.

The SOAPP(R) Repowering Screening Module conducts a screening analysis that provides a preliminary assessment of the viability of repowering an existing unit and location considering use of different technologies (including CCR, HWBR, SBLR, FWHR, CFBC, PFBC, and GCC). The Screening Module will identify major site-specific limitations and estimate technology performance and costs, enabling the user to identify which technology options are worth evaluating further in a more detailed analysis.

Once the technology options have been narrowed down using the Screening Module, another software tool, the SOAPP(R) REPO CC WorkStation can then be used to provide a more in-depth analysis for repowering options that involve combined-cycle repowering of existing fossil steam plants.  The WorkStation allows for input of detailed site-specific data and can generate any or all of the following conceptual design deliverables:

       Design criteria 
       Equipment reuse plan 
       Heat balance 
       Performance and emissions summaries 
       Equipment list (includes sizing) 
       Process flow and piping diagrams 
       General arrangement drawings 
       Capital cost estimates 
       O&M cost estimates 
       Financial analysis

The WorkStation allows evaluation of numerous equipment options and configurations, allowing the user to change input variables and option selections in order to conduct sensitivity analyses and select the optimum system design from multiple options and scenarios.  SOAPP(R) can replace the need to employ a team of engineering staff or outside consultants that would be necessary to conduct a similar analysis.

Fuel Selection

Factors that influence fuel selection include fuel availability, fuel costs, system efficiency, technology costs, technology reliability, air pollution limits, and waste disposal costs.  Table 2 presents electricity generation fuel costs (in dollars per million BTU heat content) projected by the DOE Energy Information Administration (EIA) for coal, natural gas, and two types of oil for 2007 through 2010.  As can be seen, based on energy content, the cost of natural gas and oil ranges from about three to ten times higher than the cost of coal.  These costs, however, do not necessarily reflect power generation costs because they do not take into consideration the different efficiencies of different types of combustion systems.


             Table 2.  Projected Fuel Costs Based on Heat Content
                                   Fuel Type
                                     Unit
                                     2007
                                     2008
                                     2009
                                     2010
                                     Coal
                              Dollars/Million BTU
                                     $1.77
                                     $1.94
                                     $1.92
                                     $1.88
                                  Natural Gas
                              Dollars/Million BTU
                                     $7.02
                                     $9.18
                                     $6.32
                                     $6.47
                           Distillate Fuel Oil (#2)
                              Dollars/Million BTU
                                    $14.77
                                    $19.05
                                    $14.61
                                    $14.61
                            Residual Fuel Oil (#6)
                              Dollars/Million BTU
                                     $8.38
                                    $13.77
                                     $8.01
                                    $12.32

	Source: DOE EIA 2008 (Table 3).

Table 3 shows the effects that different combustion system efficiencies have on fuel costs for generating electricity.  Table 3 presents the calculated fuel costs per MWh for conventional steam boilers and combined cycle systems, based on the assumed heat rates shown in the table using the projected year 2010 fuel costs from Table 2.  The fuel costs for combined cycle are shown for both a low efficiency system (heat rate = 7,000 BTU/KWh) that might be expected for a repowered or older system and for a newer high efficiency system (heat rate = 6,000 Btu/KWh) that represents the upper end of  possible combined cycle system efficiencies  As can be seen, even when the highest efficiency combined cycle technology is factored in, the fuel cost in dollars per MWh for combined cycle using natural gas is still several times higher than the fuel cost for a conventional coal-fired steam plant.  

Table 3.  Fuel Costs per MWh Power Generated for Different Types of Generating Systems Using 2010 Projected Fuel Costs
                                       
                                       
From the mid-1990s until about 2002, the cost of natural gas was in the $2-$3/MMBTU range and as a result construction of natural gas-fired combined cycle power plants dominated new capacity additions in the US.  Since fuel costs account for about 70% of operating expenses, the recent run-up and volatility in natural gas prices have put natural gas-fired combined cycle plants at a competitive disadvantage economically compared to conventional coal-fired plants, and as a result many combined cycle generating units have reduced their capacity utilization rates (Donaldson and Mukherjee 2006).  This has increased the economic viability of the consideration for repowering using solid fuel-based systems, including replacing all or a portion of the natural gas at existing combined cycle generating units with syngas derived from coal using GCC technology.  For facilities that are currently fueled by oil or natural gas, repowering using combined cycle technology is still an attractive option due to the higher generating efficiencies.  

Despite the higher fuel price, natural gas as a fuel source is still attractive because it produces lower air emissions.  The need for construction and operation of additional air pollution control equipment and for waste disposal add to the cost of using solid fuels.  The prospect of future limits on carbon dioxide emissions from climate legislation will add another important economic factor to be considered in the fuel selection decision, and will favor fuels and generating systems with low specific CO2 emissions (gm/KWh).  Table 4 presents the range of specific CO2 emission rates for different fuel types and different combustion system generating efficiencies.  The table shows the typical range of efficiency for gas turbines (GT), steam power plants (SPP), and combined cycle power plants (CCPP).  

          Table 4.  Specific CO2 Emissions Rates for Different Fuels 
                     and Different Combustion Technologies
                                       
	Source: Fränkle 2006.

While natural gas has the best performance with respect to reducing CO2 emissions, as discussed above it is a more expensive fuel and is more prone to price fluctuations and concerns about ability to meet future demand.  Solutions for reducing high CO2 emission rates (especially for coal-fired power plants), such as CO2 sequestration technology (which is still in the development stage), will add to the capital and operating costs of power plants fueled by coal.  However, the proven coal reserves in the US, the expectations that the price of coal will remain low relative to other fuels, and the availability of transportation infrastructure at many existing facilities makes coal an attractive fuel source for future repowering options. 

The current uncertainty about the future costs of climate legislation, along with public opposition, has slowed the pace of construction of new coal-fired power plants.  This, combined with the uncertainty of future fuel prices, has injected a great deal of uncertainty into the reliability of current projections regarding repowering and new capacity additions.  Once the specific requirements of climate legislation are established and the magnitude of the cost of CO2 emissions becomes clear, power companies will be better able to predict the costs of each fuel option.

The availability and cost of transporting different fuel types will also play a role in fuel selection.  It will affect the cost of the fuel, as well as the cost of constructing the necessary transportation infrastructure for fuels not currently available at the site.  Proximity to natural gas mainlines is an important factor in determining the costs of repowering with natural gas.  Because of these differences in availability and costs, the mix of repowering options selected will vary in different regions of the US.  Also, in areas where existing air pollution levels are high, the selected fuels and repowering options will tend to be limited to those that minimize air emissions.

Projecting Future Repowering for former Phase II Facilities

EPA's economic impact analysis includes future projections of changes in available generating capacity.  The analysis, which uses the IPM model, provides projections for generating capacity changes during the years 2013, 2015, 2017, and 2020.  These projections distinguish between existing capacity that is retained, capacity of units that are repowered, and new capacity additions.  The existing capacity retained and the capacity of units repowered is estimated for each facility on an individual unit level.  Thus, the IPM model can provide a spreadsheet identifying specific predictions as to which facilities and units will be repowered.  New capacity additions are only projected on a NERC regional basis, and do not identify whether these capacity additions will be at greenfield sites or new unit construction at existing power plants (e.g., a full repowering at a retired facility).  It is probably reasonable to assume that, in most cases, the new capacity would be required to meet more stringent 316(b) limits commensurate with the 316(b) Phase I Rule. 

Repowering as defined in the in the IPM model typically consists of the conversion of existing oil/gas or coal capacity to new natural gas-fired combined-cycle capacity.  The baseline IPM model unit-level projection for the period through 2020 lists only one coal plant as being repowered using combined cycle and one unit at another coal facility as being repowered from a coal plant to coal using IGCC.  Total repowered capacity for both was less than 200MW.  The remainder of the repowering was projected to be oil/gas-fired plants converted to combined cycle.  A comparison of the new capacity of the repowered units to the capacity before repowering for all those units projected to be repowered in the US through 2020 shows that the projected increase in capacity for each unit ranges from a factor of 1.05 to 2.78, with most being assigned a factor of 2.78.  The weighted average increase in capacity for generating units repowered through 2020 is approximately 2.5. 

Table 5 provides a summary of the IPM model projections for generating capacity for new generating units and existing generating units repowered using combined cycle repowering for the years 2013, 2015, 2017, and 2020.  Capacity data for NERC regions and total US are included.  These projections are for the baseline regulatory condition (i.e., they do not include consideration of 316(b) requirements).  The baseline unit generation data is the 2003 EIA generating unit data with some modifications that include more recent plant changes.  The total baseline generating capacity for in-scope facilities that served as input for the IPM model was 453,820 MW.  

Table 5 shows the expected magnitude of repowering activities compared to new capacity additions by presenting the totals as a percent of this baseline capacity.  The values shown for each year are cumulative totals.  Note that the repowered capacity projections represent the total capacity of the repowered generating units (including existing capacity), and that the added generating capacity for repowering is approximately 60% (1 - 1/2.5) of the total repowered capacity shown.  

     Table 5.  Estimated Generating Capacity for New Generating Units and
      Existing Generating Units Repowered Using Combined Cycle Repowering
                                       
	Source: Example IPM Model Output, Abt Associates 2009.

Table 5 shows that the IPM model predicts that initially the majority of added generating capacity will be from repowering and that the addition of new capacity from construction of new units will accelerate over the period.  By 2020, roughly two thirds of added capacity will be from new additions.  Thus, the existing facility rule, which generally applies to repowered facilities, could apply to a substantial portion of new generating capacity over the period.  Of course, this data represents the IPM model baseline conditions and does not include the projected effects of promulgation of the proposed rule. 

While the IPM model provides a fairly rigorous projection, it is based mostly on the dynamics of the electricity market and the projections regarding which facilities will be repowered may not be very accurate due to limitations of the model inputs.  Potentially more accurate information on future capacity additions and repowering activities is also available from RDI Consulting for a fee.  However, given the current uncertainty with respect to the costs of climate legislation, fuel costs, and technology development, even this potentially more accurate projection may still include a great deal of uncertainty.

Effect of Repowering on Cooling Water Flow Requirements

Changes in cooling water requirements for repowered facilities will be dependent on the changes that occur in the capacity and utilization of the steam cycle component of each repowered generating unit.  With the exception of full repowering, most of the repowering options involve the addition of combustion turbine-based technology to provide for an increase in the system generating capacity, while making at most only modest changes in the capacity of the steam cycle component.  Thus, for most repowering options, the cooling water design flow or maximum flow requirement at full power for each repowered generating unit will not increase, while at the same time the generating capacity may increase up to 200% depending on the technology selected.  Repowering options that result in an increase in the amount of steam supplied to the steam turbines may result in a slight increase in the heat load processed through the condensers and thus result in an increase in the cooling water flow or an increase in the temperature rise across the condenser.  However, for most repowering projects, the design cooling water flow requirement is not expected to change significantly.

The same is not true for the average intake flow or total flow over a given period.  As noted earlier, units selected for repowering will tend to be those that are less efficient and more costly to operate.  As a result, they will tend to be operated at lower capacity utilization rates, meaning they will be operated less often and at lower power and will tend to use less cooling water.  Since repowering often results in an increase in efficiency and a decrease in the cost of generating electricity, the repowered units will likely be operated more frequently, resulting in a higher capacity utilization rate after repowering which will likely result in an increase in both the average intake flow and the total flow over time.  This is particularly true for plants where existing gas- or oil-powered units are repowered with combined cycle.  Thus, repowering has the potential for resulting in an increase in average intake flow and thus an increase in impingement mortality and entrainment.

Plants that repower only a portion of their steam generating units using combined cycle technology while retiring other units can still substantially increase their generating capacity while reducing their maximum intake flow requirements.  For example, a facility with two steam units of equal size could repower one of them with combined cycle (CCR) and retire the other and still increase the generating capacity by 25% to 50% (assuming 150% to 200% increase in unit capacity).  In such a case, the cooling water flow requirement when operating would be reduced by 50%.  The change in average intake flow may be higher or lower depending on the combination of the reduced maximum flow versus increased capacity utilization.

In the case of full repowering, the capacity of the steam cycle component is no longer constrained by the existing plant design.  The use of combined cycle or other more efficient technology should allow for an increase in generating capacity without an increase in the cooling water flow rate.  And even when steam capacity is increased, it is likely that other cooling options will be employed for this added capacity and thus the maximum intake flow rate will not be increased.  However, it is also likely that new generating technology will be more economical and result in an increase in the capacity utilization rate.  Therefore, an increase in the average intake flow rate compared to that of the existing system before it was retired can be expected.

Example Facilities

A brief description of some example facilities that were repowered using combined cycle and solid fuel repowering options are provided below.

Full Repowering - Pulverized Coal-Fired to Natural Gas Combined Cycle

Port Washington Generating Station, Port Washington, WI  -  Wisconsin Energy
(Sources: Peltier 2008; Wicker 2005; WI DNR 2002.)

A 1935-era power plant was demolished and replaced by two 545 MW high-efficiency natural gas-fired combined cycle generating units.  The project was done in two phases with units coming online in 2005 and 2006.  Each new unit consisted of two combustion turbines, two HSRGs, and one steam turbine generator.  The original pulverized coal steam plant had five 80 MW generating units (four were operating at 320 MW total capacity in 2000) and held the record as the highest efficiency plant at 32% from 1935 to 1948 (heat rate = 10,800 BTU/KWh).  A 16-mile lateral natural gas pipe from Jackson, Wisconsin was constructed to provide fuel.  The 52-acre plant located on the south end of Port Washington, Wisconsin was typical in size for this type of plant.  The new generating units cover about 10 acres.  Construction was hampered by access being limited to only one direction, and the design of the HSRGs was modified to fit into the old building footprint.  Some of the older buildings and the west wall of the existing power house were retained.  The 450 ft by approximately 1,000 ft coal dock and coal storage area is no longer in use and it appears that this area would have provided sufficient space for installation of closed loop cooling towers.

The new plant operates as an intermediate load facility operating 16 hours per day, 5-7 days per week and withdraws 565,000 gpm of cooling water from Lake Michigan.  The design intake flow reported in the 2000 survey was 550,000 gpm.  However, it appears that no new pumping capacity was added and that the survey DIF may not have included total service pump capacity of 15,000 gpm.  Thus, while the design intake flow rate appears to have remained the same or increased by about 3%, the generating capacity has increased by a factor of 3.2 (220%).  The cost of the entire new plant was approximately $669 million (or $614/KW).

Combined Cycle Repowering  -  Coal-Fired to Natural Gas Combined Cycle

Grand Tower Power Plant, Grand Tower, Illinois  -  Ameren Energy
(Sources:  Burns & McDonnell 2009; Ameren Energy 2009.)

In 2001, two 1950s-vintage pulverized coal-fired steam electric units were repowered with natural gas-fired combined cycle using the existing steam turbine generators.  Units 3 and 4, previously rated at 82 and 104 MW, are now rated at 90 and 112 MW.  The units were modified by adding one 176 MW combustion turbine generator and one HRSG to each unit.  The new combustion turbines and HRSGs provide steam to the existing steam turbines, and total system capacity is 550 MW.  The result is a generating capacity increase by a factor of 2.98.  The existing coal-fueled boilers and all associated systems will be retired in-place (Ameren 2009). 

The plant withdraws once-through cooling water from the Mississippi River.  No information is available concerning changes in cooling water withdrawal rates, but it is likely that the design capacity remained unchanged.

Combined Cycle Repowering  -  Oil to Natural Gas

Sanford Plant, Sanford, Florida  -  Florida Power & Light
(Source:  Peltier 2004.)

The original plan was to repower Unit 3 (a 1950s-vintage 150 MW oil-fired generating unit) and Unit 4 (one of two 1970s-era 400 MW oil-fired generating units).  The older Unit 3 was cooled using once-through cooling water from the St. Johns River and the two 400 MW Units 4 and 5 are cooled using a cooling pond.  Capacity utilization for Unit 3 was expected to increase from 30% to 98%.  The public was concerned that manatees might be attracted to the increased flow of heated cooling water during the winter, making them more susceptible to injury by watercraft. As a result, FPL decided to repower both of the 400 MW Units 4 and 5 instead.  The repowered Units 4 and 5 are cooled by recirculating cooling water through the existing cooling pond.  Another benefit of repowering Unit 5 instead of Unit 3 was that less oil would be used and thus there would be less oil barge traffic on the St. Johns River.  Total oil barge traffic was reduced by 90%.

Each unit was repowered by adding a power block consisting of four combustion turbines feeding a single HSRG that provided steam to the 400 MW existing steam turbines.  Each repowered unit produces 938 MW for a total new capacity of 1,876 MW, increasing the capacity of the two units by a factor of 2.35.  The existing steam turbines remained in operation until after the combustion turbine HSRG power blocks were completed.  The existing 400 ft stacks and boilers were not demolished until after the new power blocks were commissioned.

Unit 5 construction began January 2000 and was completed June 2002.  Unit 4 construction started March 2000 and was completed May 2003.  Total cost was approximately $600 million dollars (or $320/KW).

Atmospheric Fluidized Bed Combustion Repowering  - Oil/Gas to Solid Fuel (Coal and Petroleum Coke)

Northside Generating Station, Jacksonville, Florida - JEA
(Sources:  Peltier 2002; DOE NETL 2003.)

Installed two advanced fluidized bed combustors to provide steam to the Units 1 and 2 (297 MW each) steam turbines which were originally powered by oil/gas.  Units 1 and 3 have been in operation since 1966 and 1977, respectively, at an annual capacity factor of 40%.  Unit 2 has not been in operation since 1983.  Unit 3 will continue to operate as a conventional 564-MW oil/gas-fired steam unit.  The generating capacity of the existing Units 1 and 2 turbines will remain nearly the same with a heat rate of 9950 BTU/ KWh for an overall efficiency of 34%.  With Unit 2 coming back online and an increase of the capacity factor to 90%, power generation will increase by 250%.  Despite this increase in power generation, the total air emissions will be reduced by 10% which includes the continued contributions of the Unit 3 fueled by oil/gas.

Construction includes installation of two large 400 ft diameter aluminum fuel domes, primarily intended to keep the fuel dry and also to control fugitive dust and storm runoff.  Open storage of coal in coastal areas increases moisture content, which reduces combustion efficiency.  Construction also includes the first continuous ship fuel unloader in the US.  The continuous loader will eliminate the possibility of fuel spills into the St. Johns River by transferring fuel through an enclosed conveyor system from dock to boiler.

Unit 2 was completed first in 2001 as part of DOE's Clean Coal Technology (CCT) Demonstration Program and Unit 1 was completed in 2002.  Total cost for Unit 2 was $309 million (or $1,039/KW).

Gasification Combined Cycle Repowering  -  Coal to Coal/Coke

Wabash River Power Station, West Terre Haute, IN - Wabash Valley Power Association 
(Source:  DOE NETL 2002.)

The Wabash River plant has six generating units that prior to the project had a total nameplate capacity of 973 MW.  Unit 1 (the oldest), having a nominal capacity of 99 MW, was repowered by adding a coal gasification process integrated with a new 192 MW combustion turbine and an HRSG.  The repowered unit has a total generating capacity of 262 MW net.  Thus, generating capacity was increased by a factor of 2.75.  Power used to operate process equipment was 36 MW.  The system was tested on high sulfur coal and petroleum coke which had a sulfur content of 5%.

In the process, fuel is ground and fed in a water slurry to the gasifier in which the coal is partially combusted using 95% oxygen gas at high temperature and pressure.  The oxygen is generated onsite.  The fuel is converted almost completely to syngas consisting of hydrogen, carbon monoxide and carbon dioxide, water vapor, and a small amount of carbonyl sulfide (COS).  Steam is generated when the hot syngas is cooled in order to allow for gas processing.  Gas processing includes particulate removal, wet scrubbing to remove chlorides and volatile metals, conversion of COS to hydrogen sulfide (H2S).  H2S and some CO2 are removed in an acid gas removal system.  H2S is then processed into a pure sulfur product with overall sulfur recovery of 98%.  The syngas is then moisturized, superheated and sent to the combustion turbine.  While in a conventional combined cycle system most of the steam is generated by the HSRG from the combustion turbine exhaust gases, in this system about two-thirds of the high pressure steam available to power the existing steam turbine is generated from the process used to cool the hot syngas.  The system heat rate was 8,900 BTU/KWh, which was equivalent to an efficiency of 38.3%.  Air emission levels were well within all Clean Air Act requirements.

Being a demonstration project, the plant experienced operating problems typical of an evolving technology.  These problems were resolved over time, with plant availability being only 22% the first year, increasing to 44% the second year and 60% by the third year.  Total cost was $416.6 million (or $1,590/KW).  The process was designed to produce very low SOX emissions, which added about $100/KW to the costs.  It was estimated that, if a greenfield project was constructed using knowledge learned from this project, its capital cost would be $1,275/KW and heat rate would be 8,250 BTU/KWh (41.4% efficiency). 
 

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Burns & McDonnell.  520-MW Steam Turbine Repowering  --  Grand Tower, IL.  Project Description.  2009.  Accessed on March 16, 2009 at website:  http://www.burnsmcd.com/portal/page/portal/Internet/Locations/St.%20Louis/StLouis%20PD%20Repository/520-MW%20Steam%20Turbine%20Repowering.

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