Nation’s electric companies advancing climate solutions

As of August, close to a dozen bills have been introduced in Congress to further reduce the country’s carbon dioxide (CO2) and other greenhouse gas (GHG) emissions. Some proposals have called for cutting the country’s emissions by as much as 90 percent from 1990 levels by 2050. The electric power industry climate change principles can help guide the legislative debates over lowering the country’s GHG emissions, while at the same time maintaining an affordable and reliable electricity supply.

These principles emphasize that to be effective, any long-term climate strategy must be economy-wide. It must minimize cost increases to customers and do no harm to the U.S. economy. And it must be technology driven. Policy-maker support of technologies that can lower coal-based power plant CO2 emissions, and then eventually capture and store those emissions, will be especially important.

Achieving the CO2 emissions reductions targets that are being discussed on Capitol Hill will require a sustained commitment to the development and cost-effective deployment of a full suite of CO2 -reducing technologies. Nuclear power, for example, is the only zero-emitting, new baseload generation option currently available.

Technologies that improve energy efficiency, such as advanced combustion technologies, must also play a role in reducing the country’s CO2 emissions. To derive significant emissions reductions from efficiency, though, will require new regulatory and business models for states and electric utilities. These models will be needed to ensure that energy efficiency can stand alone as a business for utilities in both regulated and unregulated states.

Edison Electric Institute (EEI) has commissioned a study that analyzes a variety of business model prototypes. Some models include methods of sharing energy savings with consumers and shareholders; others simply treat energy efficiency like any other expenditure, such as power plant construction or other infrastructure improvements.

Advanced coal plant technologies
But to really reduce the power sector’s CO2 emissions will require that the nation make an investment in advanced coal plant technologies. A suite of technology options will be needed to improve the thermal efficiency of existing coal plants, create a new generation of advanced coal combustion and gasification technologies, and eventually capture coal plant CO2 emissions and permanently store them.

Making efficiency upgrades to the turbines, boilers and the milling systems used to grind coal in existing plants is a practical way to reduce CO2 emissions in the near term. The potential efficiency opportunities at a given plant can range as high as 10 to 12 percent, with typical efficiency opportunities that are perhaps half that level. A 5 percent improvement in the efficiency of the nation’s overall coal fleet would lower the industry’s CO2 emissions by about 100 million metric tons every year.

Unfortunately, concerns over the impact of new source review (NSR) regulations can discourage power plant owners from initiating these efficiency upgrades. The industry is encouraged by recent efforts from the U.S. Environmental Protection Agency to revise portions of its NSR regulations in order to achieve progress on this issue.

The thermal efficiency of today’s traditional pulverized coal plants average between 33 to 35 percent. Investing in plants with advanced combustion technologies—”supercritical” and “ultra-supercritical” pulverized coal, and circulating fluidized bed (CFB)—along with gasification technologies (commonly known as integrated gasification combined cycle, or IGCC), can raise these efficiency levels to as high as 45 percent.

There will certainly be a cost premium associated with these more efficient plants. Many are estimated to cost 20 to 50 percent more than traditional plants. Importantly though, besides helping to lower CO2 emissions, the higher efficiencies—that is, producing the same electrical output with lower fuel input—will also help to greatly reduce sulfur dioxide (SO2), nitrogen oxide (NOX), particulate matter and mercury emissions from these new plants.

Carbon capture and storage
Along with more efficient coal plants, carbon capture and storage (CCS) will also be critical for reducing the industry’s CO2 emissions. CO2 can be captured either pre- or post-combustion. In an IGCC plant, the CO2 is removed pre-combustion. The CO2 is separated from a relatively small volume of synthetic gas (syngas) at high pressure before combustion. Since the CO2 is already under pressure, less energy is required to compress it for pipeline transport. The pre-combustion capture technologies can use a variety of physical solvents to capture the CO2. These are commercially available today, but they have never been integrated with a coal-based IGCC plant.

The traditional pulverized coal plant uses air as an oxidant for combustion. This creates a number of challenges for capturing CO2. Key among them:
•A large volume of flue gas with a low concentration of CO2 (typically 12 to 14 percent), which means more energy is required to remove it.
•Air is 80 percent nitrogen, which leaves trace impurities in the flue gas—these may reduce the effectiveness of the processes used to absorb the CO2
•Compressing the captured CO2 for pipeline transportation—moving from atmospheric pressure to pipeline pressure—takes a lot of energy.

The use of oxygen instead of air—oxycombustion—in a pulverized coal plant would help to reduce the amount of energy required to capture the CO2 post-combustion. Oxycombustion does this by:
•Producing a higher concentration (90 percent) of CO2 in the flue gas
•Eliminating the need for energy-intensive gas separation
•Significantly reducing need for costly “clean-up” equipment.

Oxycombustion, however, is more costly due to the expense of the oxygen, and the oxygen is combustible, which requires more training and caution to use.

To date, chemical absorption is the only technique that has been used to capture CO2 from flue gas. Analysis conducted at the National Energy Technology Laboratory shows that CO2 capture using this method would raise the cost of electricity from a newly built supercritical coal power plant by 75 percent or more. DOE’s goal is to cut that penalty to just 20 percent for an existing pulverized coal facility by 2012, and to only 10 percent for a new IGCC plant or another type of pre-combustion capture technology.

There are a number of longer-term technology strategies for capturing CO2 emissions post-combustion from coal plants. These efforts are important because they may allow power generators to build zero or near-zero emissions plants using current technology.

One such post-combustion CO2 capturing technology being studied is chilled ammonia. The chilled ammonia process takes flue gas, which is typically at about 130 degrees Fahrenheit, and cools it to 32 to 50 degrees Fahrenheit. After it cools, it passes through a CO2 absorber, where it is absorbed with ammonia carbonate. The absorption occurs at low temperature, preventing ammonia release but achieving high capture efficiency. In chilling the flue gas, the system also recovers large quantities of water for recycling.

Smaller-scale carbon-separation systems are available to serve the industrial market for CO2, but none is ready for the size of a power plant, in terms of either cost or performance. Some, though, represent potential “breakthrough technologies.” One of these involves metal organic frameworks (MOFs). MOFs are nano-scale organic/inorganic structures to which CO2 in flue gases will stick. Often referred to as crystal “sponges” because of their ability to capture other substances, these new materials are constructed so that, incredibly, just one gram has the surface area of a football field.

Electro-catalytic oxidation, which has proven effective in reducing sulfur dioxide, nitrogen oxides, mercury, and fine particulate matter, is another potential technology for capturing CO2 in the flue gas. So too is a research project using what are known as ionic liquids to capture CO2 from post-combustion flue gases. Discovered only about 12 years ago, ionic liquids are salts that are liquid at room temperature and do not evaporate. According to a 2005 DOE presentation, they have demonstrated the ability to absorb large amounts of CO2.

Accelerated technical and financial support could make a number of these technologies commercially available within the next 15 years, with full-scale implementation taking another decade or so. Of course, the captured CO2 must then be permanently stored or used so it does not enter the atmosphere. Right now, most experts believe the bulk of captured CO2 could be stored underground in a variety of geologic formations, including depleted oil and gas reservoirs, deep saline formations and basalts.

Electric Company Applications
The nation’s electric utility companies are moving ahead with several advanced coal technology plants around the nation to begin the development, demonstration and commercialization process. A few examples are listed below by combustion technology.

• At present, there are two operating IGCC power plants in the U.S.—the 260-megaWatt (MW) plant owned by TECO Energy in Polk County, Florida, and a 292-MW facility in West Terre Haute, Indiana, which was recently sold by Duke Energy to the Wabash Valley Power Association.
• TECO Energy’s subsidiary, Tampa Electric, has begun the process to build a proposed 632-MW IGCC facility on the site of its existing Polk Power Station. And Duke Energy and Vectren Energy Delivery of Indiana have filed an application with the Indiana Utility Regulatory Commission to construct an approximately 630-MW IGCC plant in Edwardsport, Indiana.
• In a joint venture with the Orlando Utilities Commission, Southern Power Co., a unit of Southern Co., has announced its plans to build a 285-MW IGCC plant in Orlando, which is due for completion in December 2010.
• American Electric Power (AEP) is seeking regulatory approval to build commercial-scale IGCC plants in West Virginia and Ohio.
• Edison International and BP have proposed a 500-MW IGCC plant in Carson, California, that would use petroleum coke produced at California refineries. The captured CO2 would be transported by pipeline to an oilfield and injected into reservoir rock formations thousands of feet underground, both stimulating additional oil production and permanently trapping the CO2.

• Dominion Virginia Power, a subsidiary of Dominion, has submitted an application with the state for permission to build a 585-MW CFB plant in Wise County, Virginia. The primary fuel would be coal, with the potential to burn up to 20 percent biomass.
• Cleco Corp., based in central Louisiana, has announced that it will build a 600-MW CFB plant that will use petroleum coke, a byproduct of the oil-refining process, and other solid materials as its fuel source. The plant is scheduled to open in mid-2009.

• AEP is planning two ultra-supercritical pulverized coal plants, a 950-MW plant in Oklahoma and a 600-MW plant in Arkansas.
• MidAmerican Energy Co. is completing an advanced 790-MW supercritical power plant at its Council Bluffs Energy Center in Iowa.
• Duke Energy Carolinas is planning to construct an 800-MW supercritical plant in North Carolina.

Carbon Capture and Storage
The nation’s electric companies are also advancing a number of CCS projects. AEP announced three separate CCS projects. AEP will install a chilled ammonia post-combustion project on its 1,300-MW Mountaineer Plant in New Haven, West Virginia, in 2008. The 30-MW product validation will capture up to 100,000 metric tons of CO2 per year that will be stored in deep saline aquifers at the site.
Following the validation at Mountaineer, AEP plans to install a chilled ammonia post-combustion system on one of the 450-MW coal-fired units at its Northeastern Station in Oologah, Oklahoma, in late 2011. The system is expected to capture about 1.5 million metric tons of CO2 a year that will be used for enhanced oil recovery.
AEP also plans to conduct a feasibility study of oxy-coal combustion technology. Following a pilot demonstration, AEP will select an existing AEP plant site for commercial-scale installation. The oxy-coal combustion technology is expected to be in service on an AEP plant in the 2012-2015 period.
Milwaukee-based We Energies is conducting a yearlong demonstration of a chilled ammonia system at its 1,210-MW power plant in Pleasant Prairie, Wisconsin. During this time, the Electric Power Research Institute will conduct an extensive test program to collect data and evaluate technology performance. Results of the demonstration project are anticipated to be published in late 2008.
FirstEnergy Corp. is planning pilot-scale testing of an electro-catalytic oxidation technology at its R.E. Burger Plant in Shadyside, Ohio by early 2008. Once captured, the CO2 will be transported to an 8,000-foot test well that was drilled at the Burger Plant earlier this year, and then sequester it underground.

The electric power industry is working with the DOE in a program that will integrate the carbon capture and storage technologies. This program, called FutureGen, is a $950-million initiative—with $700 million coming from the federal government and the rest from industry—to build a commercial-scale coal-fired power plant that has essentially zero emissions.
The program goals are to capture and store more than 90 percent of a 275- MW pilot plant’s CO2 emissions, with the potential for almost 100 percent. In addition, the plant will:
• Remove more than 99 percent of its SO2 output.
• Cut nitrogen oxide emissions to less than 0.05 pounds per million Btus.
• Reduce particulate releases to less than 0.005 pounds per million Btu.
• Eliminate more than 90 percent of the mercury emissions.
• And have an availability factor of more than 85 percent.

With groundbreaking set for 2009 and initial operation planned for 2012, the new plant will rise at one of four sites in either Illinois or Texas. DOE has indicated that it will announce its decision in November 2007.
The nation’s electric companies are also continuing their voluntary efforts to reduce GHG emissions with the federal government. Since 1994—when EEI joined the U.S. Department of Energy in the Climate Challenge—the electric utility industry has led all other industrial sectors in reducing GHG emissions. In fact, the industry’s voluntary efforts in 2005 alone eliminated an estimated 267 million metric tons of CO2 emissions—nearly two-thirds of the total reductions and offsets reported to the government that year. Through various programs now under way—including Power PartnersSM, the Asia-Pacific Partnership on Clean Development and Climate (APP), and individual company efforts—that commitment continues today.
The long-term goal of APP is to establish an information flow between the member nations on engineering concepts and best practices’ experiences of new coal-based plant technologies, such as IGCC units, and the related issues of CCS. AEP, Southern Co., and TECO Energy late last year, hosted the first round of utility site visits for the six member nations participating in the APP. Approximately 100 utility executives and engineers from Australia, China, India, Japan, South Korea and the United States visited the American utilities’ power plants to examine existing methods for reducing power plant emissions, and to study advanced clean coal systems, including IGCC technology.
More site visits are now being organized through the Edison Foundation. These visits will focus on a variety of technologies to reduce carbon emissions, including pumped storage/hydro, preventative maintenance/optimization, renewable energy, energy efficiency/demand side management, and transmission and distribution.

For more information on the electric power industry’s climate change programs and efforts, please visit


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