Integrated Gasification Combined Cycle
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^{Clean Coal Technology & The President's Clean Coal Power Initiative}

"Clean Coal Technology" describes a new generation of energy processes that sharply reduce air emissions and other pollutants compared to older coal-burning systems. In the late 1980s and early 1990s, the U.S. Department of Energy conducted a joint program with industry and State agencies to demonstrate the best of these new clean coal technologies at scales large enough for companies to make commercial decisions. More than 20 of the technologies tested in the original program achieved commercial success.

The early program, however, was focused on the environmental challenges of the time - primarily concerns over the impact of acid rain on forests and watersheds. In the 21st century, additional environmental concerns have emerged - the potential health impacts of trace emissions of mercury, the effects of microscopic particles on people with respiratory problems, and the potential global climate-altering impact of greenhouse gas emissions.

With coal likely to remain one of the nation's lowest-cost electric power suppliers for the foreseeable future, President Bush has pledged a new commitment to even more advanced clean coal technologies. As the President said in presenting his National Energy Policy to the American public on May 17, 2001 , "More than half of the electricity generated in America today comes from coal. If we weren't blessed with this natural resource, we would face even greater energy shortages and higher prices today. Yet, coal presents an environmental challenge.  So our plan funds research into new, "clean coal technologies."

Building on the successes of the original program, the new clean coal initiative encompasses a broad spectrum of research and large-scale projects that target today's most pressing environmental challenges.

Initially, the demonstration portion of the program, the Clean Coal Power Initiative, is providing government co-financing for new coal technologies that can help utilities meet the President's Clear Skies Initiative to cut sulfur, nitrogen and mercury pollutants from power plants by nearly 70 percent by the year 2018. Also, some of the early projects are showing ways to reduce greenhouse gas emissions from coal plants by boosting the efficiency at which they convert coal to electricity or other energy forms.

Coal gasification offers one of the most versatile and cleanest ways to convert the energy content of coal into electricity, hydrogen, and other energy forms.

The first pioneering coal gasification electric power plants are now operating commercially in the United States and in other nations, and many experts predict that coal gasification will be at the heart of the future generations of clean coal technology plants for several decades into the future. For example, at the core of the U.S. Department of Energy's FutureGen power plant of the future will be an advanced coal gasifier.

Rather than burning coal directly, gasification breaks down coal - or virtually any carbon-based feedstock - into its basic chemical constituents. In a modern gasifier, coal is typically exposed to hot steam and carefully controlled amounts of air or oxygen under high temperatures and pressures. Under these conditions, carbon molecules in coal break apart, setting into motion chemical reactions that typically produce a mixture of carbon monoxide, hydrogen and other gaseous compounds.

Coal Gasification, in fact, may be one of the best ways to produce clean-burning hydrogen for tomorrow's automobiles and power-generating fuel cells. Hydrogen and other coal gases can also be used to fuel power-generating turbines or as the chemical "building blocks" for a wide range of commercial products.

The Energy Department's Office of Fossil Energy is working on coal gasifier advances that enhance efficiency, environmental performance, and reliability as well as expand the gasifier's flexibility to process a variety of feedstocks (including biomass and municipal/industrial waste).

Environmental Benefits

The environmental benefits stem from the capability to cleanse as much as 99 percent of the pollutant-forming impurities from coal-derived gases. Sulfur in coal, for example, emerges as hydrogen sulfide and can be captured by processes used today in the chemical industry. In some methods, the sulfur can be extracted in a form that can be sold commercially. Likewise, nitrogen typically exits as ammonia and can be scrubbed from the coal gas by processes that produce fertilizers or other ammonia-based chemicals.

The Office of Fossil Energy is also exploring advanced synethesis gas cleaning and conditioning processes that are even more effective in eliminating emissions from coal gasifiers. Multi-contaminant control processes are being developed that reduce pollutants to parts-per-billion levels and are effective in cleaning mercury and other trace metals in addition to other impurities.

Coal gasification may offer a further environmental advantage in addressing concerns over the atmospheric buildup of greenhouse gas emissions, such as carbon dioxide emissions. If oxygen is used in a coal gasifier instead of air, carbon dioxide is emitted as a concentrated gas stream. In this form, it can be captured more easily and at lower costs for ultimate disposition in various sequestration approaches. (By contrast, when coal burns or is reacted in air, 80 percent of which is nitrogen, the resulting carbon dioxide is much more diluted and more costly to separate from the much larger mass of gases flowing from the combustor or gasifier.)

Efficiency Benefits

Efficiency gains are another benefit of coal gasification. In a typical coal combustion plant, heat from burning coal is used to boil water, making steam that drives a steam turbine-generator. Only a third of the energy value of coal is actually converted into electricity by most combustion plants, the rest is lost as waste heat.

A coal gasification power plant, however, typically gets dual duty from the gases it produces. First, the coal gases, cleaned of their impurities, are fired in a gas turbine - much like natural gas - to generate one source of electricity. The hot exhaust of the gas turbine is then used to generate steam for a more conventional steam turbine-generator. This dual source of electric power, called a "combined cycle," converts much more of coal's inherent energy value into useable electricity. The fuel efficiency of a coal gasification power plant can be boosted to 50 percent or more.

Future concepts that incorporate a fuel cell or fuel cell-gas turbine hybrid could achieve even higher efficiencies, perhaps in the 60 percent range, or nearly twice today's typical coal combustion plants. And if any of the remaining waste heat can be channeled into process steam or heat, perhaps for nearby factories or district heating plants, the overall fuel use efficiency of future gasification plants could reach 70 to 80 percent.

^{Higher efficiencies translate into more economical electric power and potential savings for ratepayers. A more efficient plant also uses less fuel to generate power, meaning that less carbon dioxide is produced. In fact, coal gasification power processes under development by the Energy Department could cut the formation of carbon dioxide by 40 percent or more compared to today's conventional coal-burning plant.}

^{The capability to produce electricity, hydrogen, chemicals, or various combinations while virtually eliminating air pollutants and potentially greenhouse gas emissions makes coal gasification one of the most promising technologies for the energy plants of tomorrow.}

^{COAL is our most abundant fossil fuel. The United States has more coal than the rest of the world has oil. There is still enough coal underground in this country to provide energy for the next 200 to 300 years.}

^{But coal is not a perfect fuel.}

^{Trapped inside coal are traces of impurities like sulfur and nitrogen. When coal burns, these impurities are released into the air.}

^{While floating in the air, these substances can combine with water vapor (for example, in clouds) and form droplets that fall to earth as weak forms of sulfuric and nitric acid – scientists call it "acid rain."}

There are also tiny specks of minerals – including common dirt – mixed in coal. These tiny particles don't burn and make up the ash left behind in a coal combustor. Some of the tiny particles also get caught up in the swirling combustion gases and, along with water vapor, form the smoke that comes out of a coal plant's smokestack. Some of these particles are so small that 30 of them laid side-by-side would barely equal the width of a human hair!

Also, coal like all fossil fuels is formed out of carbon. All living things - even people - are made up of carbon. (Remember - coal started out as living plants.) But when coal burns, its carbon combines with oxygen in the air and forms carbon dioxide. Carbon dioxide is a colorless, odorless gas, but in the atmosphere, it is one of several gases that can trap the earth's heat. Many scientists believe this is causing the earth's temperature to rise, and this warming could be altering the earth's climate, due to Greenhouse Gas Emissions, and the "Greenhouse Effect."

Sounds like coal is a dirty fuel to burn. Many years ago, it was. But things have changed. Especially in the last 20 years, scientists have developed ways to capture the pollutants trapped in coal before the impurities can escape into the atmosphere. Today, we have technology that can filter out 99 percent of the tiny particles and remove more than 95 percent of the acid rain pollutants in coal.

We also have new technologies that cut back on the release of carbon dioxide by burning coal more efficiently.

Many of these technologies belong to a family of energy systems called "clean coal technologies." Since the mid-1980s, the U.S. Government has invested more than $2 billion in developing and testing these processes in power plants and factories around the country. Private companies and State governments have been part of this program. In fact, they have contributed more than $4 billion to these projects.

How do you make "Clean Coal"?  Actually there are several ways.  And we call these technologies, "Clean Coal Technologies."

Take sulfur, for example. Sulfur is a yellowish substance that exists in tiny amounts in coal. In some coals found in Ohio, Pennsylvania, West Virginia and other eastern states, sulfur makes up from 3 to 10 percent of the weight of coal.

For some coals found in Wyoming , Montana and other western states (as well as some places in the East), the sulfur can be only 1/100ths (or less than 1 percent) of the weight of the coal. Still, it is important that most of this sulfur be removed before it goes up a power plant's smokestack.

^{One way is to clean the coal before it arrives at the power plant. One of the ways this is done is by simply crushing the coal into small chunks and washing it. Some of the sulfur that exists in tiny specks in coal (called "pyritic sulfur " because it is combined with iron to form iron pyrite, otherwise known as "fool's gold) can be washed out of the coal in this manner. Typically, in one washing process, the coal chunks are fed into a large water-filled tank. The coal floats to the surface while the sulfur impurities sink. There are facilities around the country called "coal preparation plants" that clean coal this way.}

^{Not all of coal's sulfur can be removed like this, however. Some of the sulfur in coal is actually chemically connected to coal's carbon molecules instead of existing as separate particles. This type of sulfur is called "organic sulfur," and washing won't remove it. Several process have been tested to mix the coal with chemicals that break the sulfur away from the coal molecules, but most of these processes have proven too expensive. Scientists are still working to reduce the cost of these chemical cleaning processes.}

^{Most modern power plants — and all plants built after 1978 — are required to have special devices installed that clean the sulfur from the coal's combustion gases before the gases go up the smokestack. The technical name for these devices is "flue gas desulfurization units," but most people just call them "scrubbers" — because they "scrub" the sulfur out of the smoke released by coal-burning boilers.}

^{How do scrubbers work?}

^{Most scrubbers rely on a very common substance found in nature called "limestone." We literally have mountains of limestone throughout this country. When crushed and processed, limestone can be made into a white powder. Limestone can be made to absorb sulfur gases under the right conditions — much like a sponge absorbs water.}

^{In most scrubbers, limestone (or another similar material called lime) is mixed with water and sprayed into the coal combustion gases (called "flue gases"). The limestone captures the sulfur and "pulls" it out of the gases. The limestone and sulfur combine with each other to form either a wet paste (it looks like toothpaste!), or in some newer scrubbers, a dry powder. In either case, the sulfur is trapped and prevented from escaping into the air.}

^{The Clean Coal Technology Program tested several new types of scrubbers that proved to be more effective, lower cost, and more reliable than older scrubbers. The program also tested other types of devices that sprayed limestone inside the tubing (or "ductwork') of a power plant to absorb sulfur pollutants.}

^{But what about nitrogen pollutants? That's another part of the Clean Coal story.}

^{Knocking the Nitrogen Oxides (NOx) Out of Coal}

Nitrogen is the most common part of the air we breathe. In fact, about 80% of the air is nitrogen. Normally, nitrogen atoms float around joined to each other like chemical couples. But when air is heated — in a coal boiler's flame, for example — these nitrogen atoms break apart and join with oxygen. This forms "nitrogen oxides" — or, as it is sometimes called, "NOx." 

Nitrogen oxides can also be formed from the atoms of nitrogen that are trapped inside coal.

In the air, nitrogen oxides are a major pollutant. It can cause smog, the brown haze you sometimes see around big cities. It is also one of the pollutants that forms "acid rain." And it can help form something called "groundlevel ozone," another type of pollutant that can make the air dingy.

^{NOx can be produced by any fuel that burns hot enough. Automobiles, for example, produce NOx when they burn gasoline. But a lot of NOx comes from coal-burning power plants, so the Clean Coal Technology Program developed new ways to reduce this pollutant.}

^{One of the best ways to reduce nitrogen oxides is to prevent it from forming in the first place. Scientists have found ways to burn coal (and other fuels) in burners where there is more fuel than air in the hottest combustion chambers. Under these conditions, most of the oxygen in air combines with the fuel, rather than with the nitrogen. The burning mixture is then sent into a second combustion chamber where a similar process is repeated until all the fuel is burned.}

^{This concept is called "staged combustion" because coal is burned in stages. A new family of coal burners called "low-NOx burners" has been developed using this way of burning coal. These burners can reduce the amount of nitrogen oxides released into the air by more than half. Today, because of research and the Clean Coal Technology Program, more than half of all the large coal-burning boilers in the United States will be using these types of burners. By the year 2000, more than 3 out of every four boilers will have been outfitted with these new clean coal technologies.}

^{There is also a family of new technologies that work like "scubbers" by cleaning NOx from the flue gases (the smoke) of coal burners. Some of these devices use special chemicals called "catalysts" that break apart the NOx into non-polluting gases. Although these devices are more expensive than "low-NOx burners," they can remove up to 90 percent of NOx pollutants.}

^{But in the future, there may be an even cleaner way to burn coal in a power plant. Or maybe, there may be a way that doesn't burn the coal at all.}

Fluidized Bed Boilers, a Bed for Burning Coal?

^{It was a wet, chilly day in Washington DC in 1979 when a few scientists and engineers joined with government and college officials on the campus of Georgetown University to celebrate the completion of one of the world's most advanced coal combustors.}

^{It was a small coal burner by today's standards, but large enough to provide heat and steam for much of the university campus. But the new boiler built beside the campus tennis courts was unlike most other boilers in the world.}

^{It was called a "fluidized bed boiler." In a typical coal boiler, coal would be crushed into very fine particles, blown into the boiler, and ignited to form a long, lazy flame. Or in other types of boilers, the burning coal would rest on grates. But in a "fluidized bed boiler," crushed coal particles float inside the boiler, suspended on upward-blowing jets of air. The red-hot mass of floating coal — called the "bed" — would bubble and tumble around like boiling lava inside a volcano. Scientists call this being "fluidized." That's how the name "fluidized bed boiler" came about.}

^{Why does a "fluidized bed boiler" burn coal cleaner?}

^{There are two major reasons. One, the tumbling action allows limestone to be mixed in with the coal. Remember limestone from a couple of pages ago? Limestone is a sulfur sponge — it absorbs sulfur pollutants. As coal burns in a fluidized bed boiler, it releases sulfur. But just as rapidly, the limestone tumbling around beside the coal captures the sulfur. A chemical reaction occurs, and the sulfur gases are changed into a dry powder that can be removed from the boiler. (This dry powder — called calcium sulfate — can be processed into the wallboard we use for building walls inside our houses.)}

^{The second reason a fluidized bed boiler burns cleaner is that it burns "cooler." Now, cooler in this sense is still pretty hot — about 1400 degrees F. But older coal boilers operate at temperatures nearly twice that (almost 3000 degrees F). Remember NOx from the page before (go back)? NOx forms when a fuel burns hot enough to break apart nitrogen molecules in the air and cause the nitrogen atoms to join with oxygen atoms. But 1400 degrees isn't hot enough for that to happen, so very little NOx forms in a fluidized bed boiler.}

^{The result is that a fluidized bed boiler can burn very dirty coal and remove 90% or more of the sulfur and nitrogen pollutants while the coal is burning. Fluidized bed boilers can also burn just about anything else — wood, ground-up railroad ties, even soggy coffee grounds.}

^{Today, fluidized bed boilers are operating or being built that are 10 to 20 times larger than the small unit built almost 20 years ago at Georgetown University. There are more than 300 of these boilers around this country and the world. The Clean Coal Technology Program helped test these boilers in Colorado, in Ohio and most recently, in Florida.}

^{A new type of fluidized bed boiler makes a major improvement in the basic system. It encases the entire boiler inside a large pressure vessel, much like the pressure cooker used in homes for canning fruits and vegetables — except the ones used in power plants are the size of a small house! Burning coal in a "pressurized fluidized bed boiler" produces a high-pressure stream of combustion gases that can spin a gas turbine to make electricity, then boil water for a steam turbine — two sources of electricity from the same fuel!}

^{A "pressurized fluidized bed boiler" is a more efficient way to burn coal. In fact, future boilers using this system will be able to generate 50% more electricity from coal than a regular power plant from the same amount of coal. That's like getting 3 units of power when you used to get only 2.}

^{Because it uses less fuel to produce the same amount of power, a more efficient "pressurized fluidized bed boiler" will reduce the amount of carbon dioxide (a greenhouse gas) released from coal-burning power plants.}

^{"Pressurized fluidized bed boilers" are one of the newest ways to burn coal cleanly. But there is another new way that doesn't actually burn the coal at all.}

^{Don't think of coal as a solid black rock. Think of it as a mass of atoms. Most of the atoms are carbon. A few are hydrogen. And there are some others, like sulfur and nitrogen, mixed in. Chemists can take this mass of atoms, break it apart, and make new substances — like gas!}

^{How do you break apart the atoms of coal? You may think it would take a sledgehammer, but actually all it takes is water and heat. Heat coal hot enough inside a big metal vessel, blast it with steam (the water), and it breaks apart. Into what?}

^{The carbon atoms join with oxygen that is in the air (or pure oxygen can be injected into the vessel). The hydrogen atoms join with each other. The result is a mixture of carbon monoxide and hydrogen — a gas.}

^{Now, what do you do with the gas?}

^{You can burn it and uses the hot combustion gases to spin a gas turbine to generate electricity. The exhaust gases coming out of the gas turbine are hot enough to boil water to make steam that can spin another type of turbine to generate even more electricity. But why go to all the trouble to turn the coal into gas if all you are going to do is burn it?}

^{A major reason is that the impurities in coal — like sulfur, nitrogen and many other trace elements — can be almost entirely filtered out when coal is changed into a gas (a process called gasification). In fact, scientists have ways to remove 99.9% of the sulfur and small dirt particles from the coal gas.} 

Gasifying coal or "Coal Gasification" is one of the best ways to clean pollutants out of coal.

^{Another reason is that the coal gases — carbon monoxide and hydrogen — don't have to be burned. They can also be used as valuable chemicals. Scientists have developed chemical reactions that turn carbon monoxide and hydrogen into everything from liquid fuels for cars and trucks to plastic toothbrushes! Today, in Tampa , Florida , and West Terre Haute, Indiana, there are power plants generating electricity by gasifying coal, rather than burning it. At a plant in Kingsport , Tennessee , coal gas is being used to make plastic for photographic film and to make methanol (a fuel that can be burned in automobile engines).}

^{Coal gasification could be one of the most promising ways to use coal in the future to generate electricity and other valuable products. Yet, it is only one of an entirely new family of energy processes called "Clean Coal Technologies" — technologies that can make fossil fuels future fuels.}

^{What is Fluidized Bed Combustion?}

Fluidized beds suspend solid fuels on upward-blowing jets of air during the combustion process. The result is a turbulent mixing of gas and solids. The tumbling action, much like a bubbling fluid, provides more effective chemical reactions and heat transfer. Fluidized bed combustion evolved from efforts to find a combustion process able to control pollutant emissions without external emission controls (such as scrubbers). The technology burns fuel at temperatures of 1,400 to 1,700 degrees F, well below the threshold where nitrogen oxides form (at approximately 2,500 degrees F, the nitrogen and oxygen atoms in the combustion air combine to form nitrogen oxide pollutants). 

The mixing action of the fluidized bed results brings the flue gases into contact with a sulfur-absorbing chemical, such as limestone or dolomite. More than 95 percent of the sulfur pollutants in coal can be captured inside the boiler by the sorbent.

Pressurized fluidized bed combustion builds on earlier work in atmospheric fluidized-bed combustion technology. Atmospheric fluidized bed combustion is crossing over the commercial threshold, with most boiler manufacturers currently offering fluidized bed boilers as a standard package. This success is largely due to the Clean Coal Technology Program and the Energy Department's Fossil Energy and industry partners’ R&D.

The popularity of fluidized bed combustion is due largely to the technology's fuel flexibility - almost any combustible material, from coal to municipal waste, can be burned - and the capability of meeting sulfur dioxide and nitrogen oxide emission standards without the need for expensive add-on controls.

The Clean Coal Technology Program led to the initial market entry of 1st generation pressurized fluidized bed technology, with an estimated 1000 megawatts of capacity installed worldwide. These systems pressurize the fluidized bed to generate sufficient flue gas energy to drive a gas turbine and operate it in a combined-cycle.

The 1st generation pressurized fluidized bed combustor uses a "bubbling-bed" technology (The joint Energy Department-American Electric Power Clean Coal Technology project at the Tidd Plant in Ohio used bubbling bed technology). A relatively stationary fluidized bed is established in the boiler using low air velocities to fluidize the material, and a heat exchanger (boiler tube bundle) immersed in the bed to generate steam. Cyclone separators are used to remove particulate matter from the flue gas prior to entering a gas turbine, which is designed to accept a moderate amount of particulate matter (i.e., "ruggedized").

A 2nd generation pressurized fluidized bed combustor uses "circulating fluidized-bed" technology and a number of efficiency enhancement measures. Circulating fluidized-bed technology has the potential to improve operational characteristics by using higher air flows to entrain and move the bed material, and re-circulating nearly all the bed material with adjacent high-volume, hot cyclone separators. The relatively clean flue gas goes on to the heat exchanger. This approach theoretically simplifies feed design, extends the contact between sorbent and flue gas, reduces likelihood of heat exchanger tube erosion, and improves SO2 capture and combustion efficiency.

A major efficiency enhancing measure for 2nd generation pressurized fluidized bed combustor is the integration of a coal gasifier (carbonizer) to produce a fuel gas. This fuel gas is combusted in a topping combustor and adds to the combustor's flue gas energy entering the gas turbine, which is the more efficient portion of the combined cycle. The topping combustor must exhibit flame stability in combusting low-Btu gas and low-NOx emission characteristics. To take maximum advantage of the increasingly efficient commercial gas turbines, the high-energy gas leaving the topping combustor must be nearly free of particulate matter and alkali/sulfur content. Also, releases to the environment from the pressurized fluid bed combustion system must be essentially free of mercury, a soon-to-be regulated hazardous air pollutant.

To reduce cost and carbon dioxide emissions, new sorbents are being evaluated. Sorbent utilization has a major influence on operating costs, and carbon dioxide emissions streams can result in the production and use of alkali-based sorbents.

Efforts are ongoing at the Power Systems Development Facility (PSDF) in Wilsonville, Alabama to ensure critical components and subsystems are ready for demonstration of 2nd generation pressurized fluidized bed combustion. The PSDF is operated by Southern Company Services under DOE contract to conduct cooperative R&D with industry.

Tests conducted at the PSDF in 1998 verified that a newly developed multi-annular swirl burner (MASB) provided the needed flame stability and low-NOx performance characteristics. Tests of promising new hot gas filter components and systems are continuing at the PSDF. Advances made to date in this critical technology area include the development of clay-bonded silicon carbide candle filters and the associated filter vessel. Efforts are currently focused on improved candle filter materials for enhanced durability under extreme temperatures and corrosive environment. New ceramics and ceramic-metallic composites are showing promise. Those passing laboratory screening tests will undergo testing at the PSDF.

Integrated Gasification Combined Cycle Project Objective

To demonstrate Integrated Gasification Combined Cycle technology in a greenfield commercial electric utility application at the 250-MWe size using an entrained-flow, oxygen-blown gasifier with full heat recovery, conventional cold-gas cleanup, and an advanced gas turbine with nitrogen injection for power augmentation and NOx control.

Technology/Project Description

Coal/water slurry and oxygen are reacted at high temperature and pressure to produce approximately 245 Btu/SCF syngas (LHV) in a gasifier. Molten ash flows out of the bottom of the gasifier into a water-filled sump where it forms a solid slag. The syngas moves from the gasifier to a radiant syngas cooler and a convective syngas cooler (CSC), which cool the syngas while generating high-pressure steam. The cooled gases flow to a water-wash syngas scrubber for particulate removal. Next, a hydrolysis reactor converts carbonyl sulfide (COS) in the raw syngas to hydrogen sulfide (H₂S) that is more easily removed. The raw syngas is then further cooled before entering a conventional amine sulfur removal system and sulfuric acid plant (SAP). The cleaned gases are then reheated and routed to a combined-cycle system for power generation. The gas turbine generates 192 MWe. Thermal NOx is controlled to 0.7 lb/MWh by injecting nitrogen. A steam turbine uses steam produced by cooling the syngas and superheated with the gas turbine exhaust gases in the HRSG to produce an additional 123 MWe. The air separation unit consumes 55 MW and auxiliaries require 10 MW, resulting in 250 MWe net power to the grid. The plant heat rate is 9,650 Btu/kWh (HHV).

Integrated Gasification Combined-Cycle Process Flow Diagram

Results Summary

Environmental

      The Integrated Gasification Combined Cycle plant removed over 97% of feedstock sulfur when operated on low-cost, high-sulfur coal, petcoke, and coal/petcoke blends.

      Typical NOx emissions were 0.7 lb/MWh, which were below the permitted limit of 0.9 lb/MWh and far  below New Source Performance Standard (NSPS) NOx levels of 1.6 lb/MWh for electric utility units. The PM emissions were typically less than 0.04 lb/ MWh, which is about 5% of those from conventional coal-fired plants equipped with electrostatic precipitation.

      The CO emissions were permitted at 99 lb/hr and averaged 7.2 lb/hr; volatile organic compound (VOC) emissions were negligible; and mercury emissions (on coal) without controls were half the potential release based on mercury levels in the coal.

Operational

      The PPS combustion turbine logged 34,800 hours over the 5-year demonstration, of which 28,500 hours were syngas-fired; syngas firing produced over 8.6 million MWh of electricity.

      The gasifier on-stream factor steadily increased, reaching 70–80% after 2½ years; overall PPS availability, with distillate fuel as backup, averaged 90% after 1½ years.

      Carbon conversion was lower than expected—in the low to mid 90% range versus the expected 97.5–98%. This rendered the ASU design capacity inadequate because of a need to recycle flyash, lowering PPS output to 235 MWe net, and required doubling the capacity of the solids handling system.

      Refractory liner life was problematic during the demonstration largely due to frequent fuel changes and attendant undesirable fluctuations in operating conditions, but a coal/petcoke blend was identified to eliminate the problem in commercial service.

      In the high-temperature heat recovery systems downstream of the gasifier, the radiant syngas cooler seals underwent design changes or corrections for fabrication defects; convective syngas coolers required geometric improvements to reduce plugging; and raw gas/ clean gas heat exchangers required removal due to stress corrosion.

      A COS hydrolysis unit had to be added to meet sulfur- reduction targets and an ion exchange unit added to prevent buildup of heat-stable salts in the MDEA unit.

      "Y” strainers and a 10 micron filter system proved critical to turbine protection from pipe-scale during start-ups.

Economic

      A capital cost of $1,650/kW (2001$) was estimated for a new 250 MWe (net) Integrated Gasification Combined Cycle plant based on the PPS configuration incorporating lessons learned. A capital cost of $1,300/kW (2001$) was estimated for a new plant that allowed for benefits derived from economies of scale, technology improvements, and replication of proven configurations to eliminate costly reinvention.

Project Summary

The company worked with the local community, state organizations, and environmental groups to make the project an environmental showcase; and engaged DOE and the technical community to move Integrated Gasification Combined Cycle closer to mainstream market acceptance. Both of these goals were met.

This project has been the recipient of numerous environmental and technological achievement awards. These include the Ecological Society of America Corporate Award, the Florida Audubon Society Corporate Award, and Power magazine's 1997 Power Plant of the Year Award. The plant was inducted into Power magazine's Power Plant Hall of Fame.

Over the 5-year demonstration period, the company carried out a systematic campaign to address and resolve the usual technical issues accompanying first-of-a-kind plants. The company showed through the demonstration that a modest-sized utility, with expertise in coalfired generation, can build and operate an Integrated Gasification Combined Cycle plant.

Environmental Performance

The Integrated Gasification Combined Cycle removed over 97% of the feedstock sulfur when operated on low-cost, high-sulfur coals, petcoke, and blends. A material balance on a 3.0% sulfur coal showed that 7.0% of the sulfur is locked up in the inert slag leaving the gasifier. The MDEA acid gas system removed 97.5% of the H₂S from the raw syngas. The COS hydrolysis to H2S proved critical to maintaining high sulfur capture efficiency because 5% of the sulfur in coal feedstocks was converted to COS (twice the amount expected) and the MDEA system was not effective in removing COS. The SAP recovered 99.7% of the sulfur it was fed.

Permit limits on NOx emissions during the PPS demonstration period were 25 parts per million by volume on a dry basis (ppmvd) corrected to 15% O₂. This value equated to 35 parts per million (ppm) as measured at the stack by a continuous emissions monitor (CEM). The permit limit is also equivalent to about 220 lb/hr NOx or 0.9 lb/MWh. Typical Polk Integrated Gasification Combined Cycle NOx emissions were about 0.7 lb/MWh, or below 30 ppm by CEM. These emission rates are a fraction of those from conventional coal-fired power plants equipped with low-NOx combustion systems. For comparison, the NSPS for electric utility units is 1.6 lb/MWh, regardless of fuel type.

The PM emissions from the Integrated Gasification Combined Cycle are typically less than 0.04 lb/MWh, which is approximately 5% of those from conventional coal-fired plants equipped with electrostatic precipitators. These near-zero emissions are the result of the concentrated, low-volume raw syngas flow and application of intensive liquid scrubbing and no less than 15 stages of liquid-gas contact.

The CO emissions, permitted at 99 lb/hr, averaged 7.2 lb/hr. The VOC emissions, permitted at 3 lb/hr, averaged 0.02 lb/hr. Mercury emissions were not regulated, but measurements taken showed that the Integrated Gasification Combined Cycle removed about half of the mercury constituent in coal feedstocks.

Operational Performance

Over the course of the demonstration, the PPS combustion turbine logged 34,800 hours of which 28,500 hours were syngas fired. The 28,500 hours of syngas firing produced over 8.6 million MWh of electricity. In producing the syngas, the gasifier typically consumed 2,500 tons of coal or coal/petcoke blends per day.

The gasifier and associated systems involved in producing clean syngas showed steady improvement in the unit's inservice (on-stream) factor over the first four years, reaching 70–80% after 2½ years, before suffering a setback in the fifth and final demonstration year. The fifth year was not considered representative. It included a lengthy planned outage to deal with gasifier refractory damage incurred by frequent feedstock changes, followed by a rare ASU forced outage and the one-time removal of sootblower lances. The on-stream factor is the percentage of time the gasifier and associated systems were in operation over the total number of hours in the year of operation. The availability of the combined-cycle power block to produce electricity from either syngas or distillate was approximately 90% over the last four years of the demonstration. The company also calculated on-peak availability because of the importance of the plant in meeting peak summer demand. The peak availabilities for 2000 and 2001 were 94.9% and 97.7%, respectively.

The following is a summary of the highlights of the technical issues that emerged during the demonstration. Most of the issues were resolved, and others served as lessons learned to improve the technology for future plants. Together, the issues served to advance the technology closer to widespread commercial deployment.

Lower-than-anticipated carbon conversion in the gasifier had major cost and performance impacts that reverberated through the Integrated Gasification Combined Cycle system. Carbon conversions of 97.5– 98% per pass were expected based on performance of smaller gasifiers. The PPS gasifier achieved per pass carbon conversion in the low- to mid- 90% range.

Even at design capacity, the ASU could not deliver enough air to meet the total gasifier oxygen requirements given the unexpectedly low carbon conversion and the resulting need to recycle flyash (which reduced fuel quality). Moreover, the company desired the flexibility to process low-quality fuels.

Essentially all carbon steel parts in contact with the slurry feedstock had to be replaced or coated with corrosionresistant materials, and high-wear areas had to be hardened.

The company evaluated numerous modifications to the slurry feed injectors in an attempt to resolve the carbon conversion issue. Only marginal improvement resulted.

A two-year gasifier refractory liner life commercial goal established for the PPS was not met during the demonstration period primarily because of frequent fuel changes. The fuel changes introduced risk in operational settings and less-than-optimal operating conditions as adjustments were made. Also, the high number of start-up and shutdown cycles experienced during the demonstration period accelerated refractory spalling.

The company carried out extensive feedstock testing during the demonstration with refractory life being a prime consideration. Testing showed that a blend of 45% Black Beauty and Mina Norte coals with 55% petroleum coke provided excellent cost and performance characteristics and the potential for long refractory liner life.

Contributing to the refractory degradation was the inability to directly measure gasifier temperatures on a realtime basis. Thermocouples failed to survive the gasifier flow path. Gasifier temperature measurements primarily relied on “inferential measurement” based on methane formation. Monitoring and control of gasifier temperature also is critical for control of slag viscosity and flyash volume.

All radiant syngas cooler seals eventually failed due to either fabrication defects or design flaws, all of which were corrected. Corrections included removal of all but 8 of the 122 sootblower lances. Only four lances are used as sootblowers. The other four serve as purge points for injection of N₂ during start-up and shutdown.

The CSC fire-tube heat exchanger was a source of frequent plugging and forced outages through 1999. The plugging primarily occurred at the CSC tubesheet inlet. In 1999, significant geometric improvements dramatically reduced plugging by more than half. Although not eliminated, CSC pluggage is deemed manageable.

The gasifier's lower-than-expected carbon conversion required twice as much fly ash and associated black water to be processed as originally designed. This increased volume essentially overwhelmed the solids handling system, precluded slag sales, and posed significant disposal costs. To resolve these issues, the company (1) doubled the capacity of the fines (predominately flyash) handling system; (2) provided the capability to recycle 100% of the settler bottoms flyash to the gasifier slurry preparation system; (3) used condensate water instead of grey water in the slag removal system and stripped the ammonia from that condensate water; and (4) added a drag conveyor and screen to de-water and separate the fly-ash from the slag. With these changes, operation on 100% coal enabled sales of the slag while recycling 100% of the settler bottom flyash and generating 235 MWe (net). The company's future plans include increasing ASU capacity to provide enough oxygen to compensate for added fuel required to boost output to the rated capacity of 250 MWe year round.

In the original Integrated Gasification Combined Cycle design, heat exchangers were incorporated downstream of the CSC to recover process heat by warming clean gas and diluent N₂ going to the combustion turbine. Flyash deposits from the raw syngas resulted in stress corrosion, cracking of the tubes, and turbine blade damage. These heat exchangers were removed because the heat recovery, less than 1.7% of the fuel's heating value, did not warrant the cost of redesign.

The company incorporated a COS hydrolysis system in 1999. An ion exchange system was subsequently added to control a high rate of heat-stable salt formation resulting from COS hydrolysis.

The only major power block forced outages during syngas- based operation resulted from failures of the raw gas/ clean gas heat exchanger (since removed) in the absence of protective “Y” strainers. The “Y” strainers had been removed for repair. “Y” strainers subsequently proved critical for start-ups because of the release of large volumes of pipe scale. To increase turbine protection and reduce “Y” strainer cleaning, a 10 micron final syngas filter was installed upstream of the syngas strainers. This filter was sized to catch a year's worth of pipe scale.

Economic Performance

The company estimated a capital cost of $1,650/kW (in 2001 dollars) for installing a new single-train 250-MWe unit at the Polk site, based on the PPS configuration and incorporating all lessons learned. This estimate reflected the cost of the plant as if it were instantaneously conceived, permitted, and erected (overnight cost) in mid- 2001. The single-train PPS configuration contributed to the high cost in that no benefits accrued from economies of scale in using common balance-of-plant systems. The company also noted a number of site-specific factors adding to high costs. The company developed another capital cost estimate, that included moderated site-specific factors and allowed benefits from economies of scale, technical improvement, and replication of proven configurations to eliminate costly re-invention. Application of these benefits reduced the estimated capital cost to $1,300/kW (2001$).

Commercial Applications

During the course of the demonstration, the company addressed the future of Integrated Gasification Combined Cycle, reflecting on typical concerns expressed by visitors, numbering over 2,500 and representing 20 countries. In regard to cost, the primary concern, The company pointed out that capital costs will be lower for next-generation Integrated Gasification Combined Cycle.  In addition the Integrated Gasification Combined Cycle demonstrations would accelerate cost reduction, and higher initial costs for Integrated Gasification Combined Cycle can be offset by long-term fuel savings. As to the associated factor of economic risk, the company observed that (1) assumption of overall plant performance risk by a single entity rather than separate entities for individual process units would reduce the difficulty in obtaining financing; (2) a return to steady economic growth in the United States would encourage potential Integrated Gasification Combined Cycle users to take a longer-term investment view, and (3) a lasting change in the expected availability or price differential of natural gas to coal would tip the risk-versus-reward scale towards Integrated Gasification Combined Cycle. Also, environmental legislation requiring mercury or CO₂ removal would provide an economic advantage to Integrated Gasification Combined Cycle over conventional coal-fired power generation because these emissions are readily removed from concentrated Integrated Gasification Combined Cycle gas streams.

As to availability, the company noted that: (1) the PPS gasifier availability is lower than can be expected for subsequent Integrated Gasification Combined Cycle plants incorporating lessons learned; (2) overall PPS availability, including operation on backup fuel, is very high; and (3) the PPS experience showed that availability can be effectively managed.

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