Hearings and Business Meetings
May 01 2006
SD-366 Energy Committee Hearing Room 02:30 PM
Dr. Antonia Herzog
Climate Center Staff Scientist, Natural Resources Defense Council
Testimony of Antonia Herzog
Staff Scientist and Climate Advocate, Climate Center
Natural Resources Defense Council
Full Committee Hearing on
Energy and Natural Resources
United States Senate
May 1st, 2006
Thank you for the opportunity to testify today on the subject of coal gasification technology. My name is Antonia Herzog. I am a staff scientist and climate advocate of the Climate Center at the Natural Resources Defense Council (NRDC). NRDC is a national, nonprofit organization of scientists, lawyers and environmental specialists dedicated to protecting public health and the environment. Founded in 1970, NRDC has more than 1.2 million members and online activists nationwide, served from offices in New York, Washington, Los Angeles and San Francisco.
One of the primary reasons that the electric power, chemical, and liquid fuels industries have become increasingly interested in coal gasification technology in the last several years is the volatility and high cost of both natural gas and oil. Coal has the advantages of being a cheap, abundant, and a domestic resource compared with oil and natural gas. However, the disadvantages of conventional coal use cannot be ignored. From underground accidents and mountain top removal mining, to collisions at coal train crossings, to air emissions of acidic, toxic, and heat-trapping pollution from coal combustion, to water pollution from coal mining and combustion wastes, the conventional coal fuel cycle is among the most environmentally destructive activities on earth.
But we can do better with both production and use of coal. And because the world is likely to continue to use significant amounts of coal for some time to come, we must do better. Energy efficiency remains the cheapest, cleanest, and fastest way to meet our energy and environmental challenges, while renewable energy is the fastest growing supply option. Increasing energy efficiency and expanding renewable energy supplies must continue to be the top priority, but we have the tools to make coal more compatible with protecting public health and the environment. With the right standards and incentives we can fundamentally transform the way coal is produced and used in the United States and around the world.
In particular, coal use and climate protection do not need to be irreconcilable activities. While energy efficiency and greater use of renewable resources must remain core components of a comprehensive strategy to address global warming, development and use of technologies such as coal gasification in combination with carbon dioxide (CO2) capture and permanent disposal in geologic repositories could enhance our ability to avoid a dangerous build-up of this heat-trapping gas in the atmosphere while creating a future for continued coal use.
However, because of the long lifetime of carbon dioxide in the atmosphere and the slow turnover of large energy systems we must act without delay to start deploying these technologies. Current government policies are inadequate to drive the private sector to invest in carbon capture and storage systems in the timeframe we need them. To accelerate the development of these systems and to create the market conditions for their use, we need to focus government funding more sharply on the most promising technologies. More importantly, we need to adopt reasonable binding measures to limit global warming emissions so that the private sector has a business rationale for prioritizing investment in this area.
Congress is now considering proposals to gasify coal as a replacement for natural gas and oil (as discussed in testimony NRDC provided before this committee in the April 24th, 2006 hearing on “Coal Liquefaction and Gasification” ). These proposals need to be evaluated in the context of the compelling need to reduce global warming emissions steadily and significantly, starting now and proceeding constantly throughout this century. Because today’s coal mining and use also continues to impose a heavy toll on America’s land, water, and air, damaging human health and the environment, it is also critical to examine the implications of a substantial coal gasification program on these values as well.
Reducing Natural Gas Demand
The nation’s economy, our health and our quality of life depend on a reliable supply of affordable energy services. The most significant way in which we can achieve these national goals is to exploit the enormous scope to wring more services out of each unit of energy used and by aggressively promoting renewable resources. While coal gasification technology has been touted as the technology solution to supplement our natural gas supply and reduce our dependence on natural gas imports, the most effective way to lower natural gas demand, and prices, is to waste less. America needs to first invest in energy efficiency and conservation to reduce demand, and to second promote renewable energy alternatives to supplement supply. Gasified coal may have a role to play but in both the short-term and over the next two decades, efficiency and renewables are the lead actors in an effective strategy to moderate natural gas prices and balance our demand for natural gas with reasonable expectations of supply.
We know that today’s natural gas prices have had a particularly significant impact on the agricultural sector by raising the cost of making fertilizer among other products. We agree that effective steps should be taken to fix this problem. In our view a package of measures to increase the efficiency of current gas uses, substitution of renewable energy for other gas uses, and judicious use of coal gasification with CO2 capture and disposal would be the most effective program. With respect to the coal gasification component of this policy package, it is important to address and prevent the additional harmful impacts to land and water that would result if incremental coal production were carried out with current mining and production practices. As pointed out later in Appendix A, current practices are causing unacceptable and avoidable levels of damage to land, water and mining communities.
Increasing energy efficiency is far-and-away the most cost-effective way to reduce natural gas consumption, avoid emitting carbon dioxide and other damaging environmental impacts. Technologies range from efficient lighting, including emerging L.E.D. lamps, to advanced selective membranes which reduce industrial process energy needs. Critical national and state policies include appliance efficiency standards, performance-based tax incentives, utility-administered deployment programs, and innovative market transformation strategies that make more efficient designs standard industry practice.
Conservation and efficiency measures such as these can have dramatic impacts in terms of price and savings. Moreover, all of these untapped gas efficiency “resources” will expand steadily, as a growing economy adds more opportunities to secure long-lived savings. California has a quarter century record of using comparable strategies to reduce both natural gas consumption and the accompanying utility bills. Recent studies commissioned by the Pacific Gas & Electric Company indicate that, by 2001, longstanding incentives and standards targeting natural gas equipment and use had cut statewide consumption for residential, commercial, and industrial purposes (excluding electric generation) by more than 20 percent.
Renewables can also play a key role in reducing natural gas prices. Adoption of a national renewable energy standard (RES) can significantly reduce the demand for natural gas, alleviating potential shortages. The Energy Information Administration (EIA) has found that a national 10 percent renewable energy standard could reduce gas consumption by 1.4 trillion cubic feet per year in 2020 compared to business as usual, or roughly 5 percent of annual demand.
Studies have consistently shown that reducing demand for natural gas by increasing renewable energy use will reduce natural gas prices. According to a report released by the U.S. Department of Energy’s Lawrence Berkeley National Laboratory, “studies generally show that each 1% reduction in national gas demand is likely to lead to a long-term (effectively permanent) average reduction in wellhead gas prices of 0.8% to 2%. Reductions in wellhead prices will reduce wholesale and retail electricity rates and will also reduce residential, commercial, and industrial gas bills.” EIA found that increasing renewable energy to 10 percent by 2020 would result in $4.9 billion cumulative present value savings for industrial gas consumers, $1.8 billion to commercial customers, and $2.4 billion to residential customers. EIA also found that renewable energy can also reduce electricity bills. Lower natural gas prices for electricity generators and other consumers offset the slightly higher cost of renewable electricity technology.
Implementing effective energy efficiency measures is the fastest and most cost effective approach to balancing natural gas demand and supply. Renewable energy provides a critical mid-term to long-term supplement. Analysis by the Union of Concerned Scientists found that a combined efficiency and renewable energy scenario could reduce gas use by 31 percent and natural gas prices by 27 percent compared to business as usual in 2020.
In contrast to these strategies, pursuing coal gasification implementation strategies that address only natural gas supply concerns, while ignoring impacts of coal, is a recipe for huge and costly mistakes. Fortunately, we have in our tool box energy resource options that can reduce natural gas demand and global warming emissions as well as protecting America’s land, water, and air.
Environmental Impacts of Coal
Some call coal “clean.” It is not and likely never will be compared to other energy options. Nonetheless, it appears inevitable that the U.S. and other countries will continue to rely heavily on coal for many years. The good news is that with the right standards and incentives it is possible to chart a future for coal that is compatible with protecting public health, preserving special places, and avoiding dangerous global warming. It may not be possible to make coal clean, but by transforming the way coal is produced and used, it is possible to make coal dramatically cleaner - and safer - than it is today.
Global Warming Pollution
To avoid catastrophic global warming the U.S. and other nations will need to deploy energy resources that result in much lower releases of CO2 than today’s use of oil, gas and coal. To keep global temperatures from rising to levels not seen since before the dawn of human civilization, the best expert opinion is that we need to get on a pathway now to allow us to cut global warming emissions by 60-80% from today’s levels over the decades ahead. The technologies we choose to meet our future energy needs must have the potential to perform at these improved emission levels.
Most serious climate scientists now warn that there is a very short window of time for beginning serious emission reductions if we are to avoid truly dangerous greenhouse gas reductions without severe economic impact. Delay makes the job harder. The National Academy of Sciences recently stated: “Failure to implement significant reductions in net greenhouse gases will make the job much harder in the future – both in terms of stabilizing their atmospheric abundances and in terms of experiencing more significant impacts.”
In short, a slow start means a crash finish – the longer emissions growth continues, the steeper and more disruptive the cuts required later. To prevent dangerous global warming we need to stabilize atmospheric concentration at or below 450 ppm, which would keep total warming below 2 degrees Celsius (3.6 degrees Fahrenheit). If we start soon, we can stay on the 450 ppm path with an annual emission reduction rate that gradually ramps up to about 2.4% per year. But if we delay a serious start by 10 years and continue emission growth at the business-as-usual trajectory, the annual emission reduction rate required to stay on the 450 ppm pathway jumps almost 3-fold, to 6.9% per year. (See Figure 1.) Even if you do not accept today that the 450 ppm path will be needed please consider this point. If we do not act to preserve our ability to get on this path we will foreclose the path not just for ourselves but for our children and their children. We are now going down a much riskier path and if we do not start reducing emissions soon neither we nor our children can turn back no matter how dangerous the path becomes.
In the past, some analysts have argued that the delay/crash action scenario is actually the cheaper course, because in the future (somehow) we will have developed breakthrough technologies. But it should be apparent that the crash reductions scenario is implausible for two reasons. First, reducing emissions by 6.9 percent per year would require deploying advanced low-emission technologies at least several times faster than conventional technologies have been deployed over recent decades. Second, the effort would require prematurely retiring billions of dollars in capital stock – high-emitting power plants, vehicles, etc. – that will be built or bought during the next 10-20 years under in the absence of appropriate CO2 emission limits.
It also goes without saying that U.S. leadership is critical. Preserving the 450 ppm pathway requires other developed countries to reduce emissions at similar rates, and requires the key developing countries to dramatically reduce and ultimately reverse their emissions growth. U.S. leadership can make that happen faster.
To assess the global warming implications of a large coal gasification program we need to carefully examine the total life-cycle emissions associated with the end product, whether electricity, synthetic gas, liquid fuels or chemicals, and to assess if the relevant industry sector will meet the emission reductions required to be consistent with the “green” pathway presented in Figure 1.
More than 90 percent of the U.S. coal supply is used to generate electricity in some 600 coal-fired power plants scattered around the country, with most of the remainder used for process heat in heavy industrial and in steel production. Coal is used for power production in all regions of the country, with the Southeast, Midwest, and Mountain states most reliant on coal-fired power. Texas uses more coal than any other state, followed by Indiana, Illinois, Ohio, and Pennsylvania.
About half of the U.S. electricity supply is generated using coal-fired power plants. This share varies considerably from state to state, but even California, which uses very little coal to generate electricity within its borders, consumes a significant amount of electricity generated by coal in neighboring Arizona and Nevada, bringing coal’s share of total electricity consumed in California to 20 percent. National coal-fired capacity totals 330 billion watts (GW), with individual plants ranging in size from a few million watts (MW) to over 3000 MW. More than one-third of this capacity was built before 1970, and over 400 units built in the 1950s—with capacity equivalent to roughly 100 large modern plants (48 GW)—are still operating today.
The future of coal in the U.S. electric power sector is an uncertain one. The major cause of this uncertainty is the government’s failure to define future requirements for limiting greenhouse gas emissions, especially carbon dioxide (CO2). Coal is the fossil fuel with the highest uncontrolled CO2 emission rate of any fuel and is responsible for 36 percent U.S. carbon dioxide emissions. Furthermore, coal power plants are expensive, long-lived investments. Key decision makers understand that the problem of global warming will need to be addressed within the time needed to recoup investments in power projects now in the planning stage. Since the status quo is unstable and future requirements for coal plants and other emission sources are inevitable but unclear, there will be increasing hesitation to commit the large amounts of capital required for new coal projects.
Electricity production is the largest source of global warming pollution in the U.S. today. In contrast to nitrogen and sulfur oxide emissions, which have declined significantly in recent years as a result of Clean Air Act standards, CO2 emissions from power plants have increased by 27 percent since 1990. Any solution to global warming must include large reductions from the electric sector. Energy efficiency and renewable energy are well-known low-carbon methods that are essential to any climate protection strategy. But technology exists to create a more sustainable path for continued coal use in the electricity sector as well. Coal gasification can be compatible with significantly reducing global warming emissions in the electric sector if it replaces conventional coal combustion technologies, directly produces electricity in an integrated manner, and most importantly captures and disposes of the carbon in geologic formations. IGCC technology without CO2 capture and disposal achieves only modest reductions in CO2 emissions compared to conventional coal plants.
A coal integrated gasification combined cycle (IGCC) power plant with carbon capture and disposal can capture up to 90 percent of its emissions, thereby being part of the global warming solution. In addition to enabling lower-cost CO2 capture, gasification technology has very low emissions of most conventional pollutants and can achieve high levels of mercury control with low-cost carbon-bed systems. However, it still does not address the other environmental impacts from coal production and transportation discussed in more detail in Appendix A.
The electric power industry has been slow to take up gasification technology but two commercial-scale units are operating in the U.S.—in Indiana and Florida. The Florida unit, owned by TECO, is reported by the company to be the most reliable and economic unit on its system. Two coal-based power companies, AEP and Cinergy, have announced their intention to build coal gasification units. BP also has announced plans to build a petroleum coke gasification plants that will capture and sequester CO2.
Another area that has received interest is coal gasification to produce synthetic natural gas as a direct method of supplementing our natural gas supply from domestic resources. However, without CO2 capture and disposal this process results in more than twice as much CO2 per 1000 cubic feet of natural gas consumed compared to conventional resources. From a global warming perspective this is unacceptable. With capture and disposal the CO2 emissions can be substantially reduced, but still remain 12 percent higher than natural gas.
In Beulah, North Dakota the Basin Electric owned Dakota Gasification Company’s Great Plains Synfuels Plant is a 900MW facility which gasifies coal to produce synthetic “natural” gas. It can produce a 150 million cubic feet of synthetic gas per day and 11,000 tons of CO2 per day. However, it no longer releases all of its CO2 to the atmosphere, but captures most of it and pipes it 200 miles to an oil field near Weyburn, Saskatchewan. There the CO2 is pumped underground into an aging oil field to recover more oil. EnCana, operator of this oil field, pays $2.5 million per month for the CO2. They expect to sequester 20 million tons of CO2 over the lifetime of this injection project.
A potential use for coal-produced synthetic gas would be to burn it in a gas turbine at another site for electricity generation. This approach would result in substantially higher CO2 emissions than producing electricity in an integrated system at the coal gasification plant with CO2 capture at the site (i.e. in an IGCC plant with carbon capture and disposal). Coal produced synthetic natural gas could also be used directly for home heating. As a distributed source of emissions the CO2 would be prohibitive to capture with known technology.
Before producing synthetic pipeline gas from coal a careful assessment of the full fuel cycle emission implications and the emission reductions that are required from that sector must be carried out before decisions are made to invest in these systems.
The chemical industry has also been looking carefully at coal gasification technology as a way to replace the natural gas feedstock used in chemical production. The motivator has been the escalating and volatile costs of natural gas in the last few years. A notable example in the U.S. of such a use is the Tennessee Eastman plant, which has been operating for more than 20 years using coal instead of natural gas to make chemicals and industrial feedstocks. If natural gas is replaced by coal gasification as a feedstock for the chemical industry, first and foremost CO2 capture and disposal must be an integral part of such plants. In this case, the net global warming emissions will change relatively little from this sector. However, before such transformation occurs a careful analysis of the life cycle emissions needs to be carried out along with an assessment of how future emissions reductions from this sector can be most effectively accomplished.
The issue of converting coal into a liquid fuel was explored in detail in testimony NRDC provided before this committee in the April 24th, 2006 hearing on “Coal Liquefaction and Gasification”. To briefly reiterate, to assess the global warming implications of a large coal-to-liquids program we need to examine the total life-cycle or “well-to-wheel” emissions of these new fuels. Coal contains about 20 percent more carbon per unit of energy compared to petroleum. When coal is converted to liquid fuels, two streams of CO2 are produced: one at the coal-to-liquids production plant and the second from the exhausts of the vehicles that burn the fuel. With the technology in hand today and on the horizon it is difficult to see how a large coal-to-liquids program can be compatible with the low-CO2-emitting transportation system we need to design to prevent global warming.
Based on available information about coal-to-liquids plants being proposed, the total well to wheels CO2 emissions from such plants would be nearly twice as high as using crude oil, if the CO2 from the coal-to-liquids plant is released to the atmosphere. Obviously, introducing a new fuel system with double the CO2 emissions of today’s crude oil system would conflict with the need to reduce global warming emissions. If the CO2 from coal-to-liquids plants is captured, then well-to-wheels CO2 emissions would be reduced but would still be higher than emissions from today’s crude oil system.
This comparison indicates that using coal to produce a significant amount of liquids for transportation fuel would not be compatible with the need to develop a low-CO2 emitting transportation sector unless technologies are developed to significantly reduce emissions from the overall process. But here one confronts the unavoidable fact that the liquid fuel from coal contains the same amount of carbon as is in gasoline or diesel made from crude. Thus, the potential for achieving significant CO2 emission reductions compared to crude is inherently limited. This means that using a significant amount of coal to make liquid fuel for transportation needs would make the task of achieving any given level of global warming emission reduction much more difficult. Proceeding with coal-to-liquids plants now could leave those investments stranded or impose unnecessarily high abatement costs on the economy if the plants continue to operate.
CO2 Capture and Disposal
Methods to capture CO2 from industrial gas streams have been in use for decades. In the U.S., for example, they are used to separate CO2 from “sour gas” at natural gas processing plants and are even in use at a few coal-fired power plants to produce CO2 for sale to the food and beverage industries. As previously mentioned, in North Dakota a large coal gasification plant captures CO2 and ships it by pipeline to an oil field in Saskatchewan, where it is injected to produce additional oil. In Wyoming, a large gas processing plant captures CO2 for sale to oil field operators in that state and in Colorado. Smaller plants in Texas do the same thing to serve oil fields in the Permian Basin.
Once captured, the CO2 must be disposed of and the currently viable approach is to inject the CO2 into deep geologic formations that are capable of permanently retaining it. Geologic injection of CO2 has been underway in the U.S. for a couple of decades as a method for producing additional oil from declining fields. Today, oil companies inject about 30 million tons annually into fields in the Permian Basin, Wyoming, Colorado and other states.
Because industrial sources can emit CO2 for free under current U.S. policy, most of the injected CO2 is supplied from natural CO2 reservoirs, rather than being captured from emission sources. Ironically, due to the lack of emission limits and the limited number of natural CO2 fields, a CO2 supply shortage is currently constraining enhanced oil recovery from existing fields. There is, of course, a huge supply of CO2 from power plants and other sources that would become available to supply this market, but that will not happen as long as CO2 can be emitted at no cost.
Such enhanced oil recovery (EOR) operations are regulated to prevent releases that might endanger public health or safety but they are not monitored with any techniques that would be capable of detecting smaller leak rates. Small leak rates might pose no risk to the local surroundings but over time could undercut the effectiveness of geologic storage as a CO2 control technique. Especially in EOR operations, the most likely pathways for leakage would be through existing wells penetrating the injection zone.
Much of the injected CO2 is also brought back to the surface with the oil produced by this technique. That CO2 is typically reinjected to recover additional oil, but when oil operations are completed it may be necessary to inject the CO2 into a deeper geologic formation to ensure permanent storage.
In addition to these EOR operations, CO2 is being injected in large amounts in several other projects around the world. The oldest of these involves injection of about 1 million tons per year of CO2 from a natural gas platform into a geologic formation beneath the sea bed off the coast of Norway. The company decided to inject the CO2 rather than vent it to avoid paying an emission charge adopted by the Norwegian government—a clear example of the ability of emission policies to produce the deployment of this technology. The Norwegian operation is intensively monitored and the results from over seven years of operation indicate the CO2 is not migrating in a manner that would create a risk of leakage. Other large-scale carefully monitored operations are underway at the Weyburn oil field in Saskatchewan and the In Salah natural gas field in Algeria.
While additional experience with large-scale injection in various geologic formations is needed, we believe enough is known to expand these activities substantially under careful procedures for site selection, operating requirements and monitoring programs. The imperative of avoiding further carbon lock-in due to construction of conventional coal-fired power plants and the capabilities of CO2 capture and storage technologies today warrant policies to deploy these methods at coal gasification plants without further delay.
Conventional Air Pollution
Dramatic reductions in power plant emissions of criteria pollutants, toxic compounds, and global warming emissions are essential if coal is to remain a viable energy resource for the 21st Century. Such reductions are achievable in coal gasification plants. In particular, integrated gasification combined cycle (IGCC) systems enable cost-effective advanced pollution controls that can yield extremely low criteria pollutant and mercury emission rates and facilitates carbon dioxide capture and geologic disposal. Gasifying coal at high pressure facilitates removal of pollutants that would otherwise be released into the air such that these pollutant emissions are well below those from conventional pulverized coal power plants with post combustion cleanup. These technologies will not be widely employed, however, without a sustained market driver, which requires vigorous enforcement of clean air standards, new limits on global warming emissions, and market oriented incentives to deploy carbon capture and disposal
Mining, Processing and Transporting Coal
The impacts of mining, processing, and transporting 1.1 billion tons of coal today on health, landscapes, and water are large. To understand the implications of continuing our current level of as well as expanding coal production, it is important to have a detailed understanding of the impacts from today’s level of coal production. A summary is included in Appendix A and was also given in testimony NRDC submitted on April 24th, 2006 to the Senate Energy and Natural Resources full committee hearing on “Coal Liquefaction and Gasification.” It clear that we must find more effective ways to reduce the impacts of mining, processing and transportation from coal before we follow a path that would result in even larger amounts of coal production and transportation.
“Carbon Capture Ready” and the “Energy Policy Act of 2005”
Among the various environmental concerns associated with coal use, the global warming emissions are particularly critical as coal fired power generation emits more carbon dioxide per unit of energy than any other power generating process. It is clear that for coal to remain a major source of electricity generation within a carbon constrained world, carbon capture and disposal technologies will have to be deployed in conjunction coal fired power plants.
The three required elements of a coal-based CO2 capture and disposal (CCD) system have all been demonstrated at commercial scale in numerous projects around the world. But there is large potential for optimization of each element to bring down costs and improve efficiency. In addition, the experience with large scale injection of CO2 into geologic formations is still limited.
For coal, the first element of a CCD system is a method to convert coal into useful energy that produces a waste stream that makes CO2 capture relatively inexpensive. The method for doing this that is commercially demonstrated is through gasification of coal. In contrast to the conventional coal combustion methods used in electric power generation, gasification converts the coal under pressure and temperature to produce a smaller gas stream with higher CO2 concentrations. This approach significantly reduces the cost and energy required to capture CO2.
In the “Energy Policy Act of 2005” (EPACT05), while there are myriad incentives for deploying coal gasification technology, there are no requirements to include CO2 capture and disposal. Scattered throughout the Act is language referring to the capability of coal gasification technology to capture its carbon emissions or to be “carbon capture ready”. However, nothing requires the facilities to actually capture and dispose of their CO2 emissions. Several examples are the following:
• Title IV – Coal - section 413 (b)(3) Western Integrated Coal Gasification Demonstration Project: “Shall be capable of removing and sequestering carbon dioxide emissions.”
• Title VIII - Hydrogen – section 805(e)(1)(A) “Fossil fuel, which may include carbon capture and sequestration;”
• Title X111 – Energy Policy Tax Incentives - section 1307(b) “Sec. 48A. (c) Definitions (5) GREENHOUSE GAS CAPTURE CAPABILITY- The term `greenhouse gas capture capability' means an integrated gasification combined cycle technology facility capable of adding components which can capture, separate on a long-term basis, isolate, remove, and sequester greenhouse gases which result from the generation of electricity.”
“Sec. 48B. (c) Definitions (5) CARBON CAPTURE CAPABILITY- The term `carbon capture capability' means a gasification plant design which is determined by the Secretary to reflect reasonable consideration for, and be capable of, accommodating the equipment likely to be necessary to capture carbon dioxide from the gaseous stream, for later use or sequestration, which would otherwise be emitted in the flue gas from a project which uses a nonrenewable fuel.”
• Title XVII – Incentives for Innovative Technologies – Section 1703(c)(1)(A)(ii) “that have a design that is determined by the Secretary to be capable of accommodating the equipment likely to be necessary to capture the carbon dioxide that would otherwise be emitted in flue gas from the plant;”
The issue I would like to address here is the definition of “carbon capture ready.” Adding carbon capture capabilities to a coal gasification power plant is not a simple modification. Without any current regulatory or economic incentives for these facilities to capture and dispose of their carbon emissions the extent of the capture modifications that will be incorporated into the gasification facilities remains extremely unclear. I would, in fact, argue that due to the vagueness of this term the result will be a “race to the bottom”, a minimal effort to incorporate the necessary design elements and equipment that would allow coal gasification plants to qualify for EPACT05 incentives.
What are the required technical details associated with coupling coal gasification plants with carbon capture and disposal? Carbon capture in a coal gasification plant occurs after the coal gasification process. I will focus on the case for electricity generation (an IGCC plant) where the syngas produced then enters a gas turbine. It is at this stage that the chemical process can be inserted to separate and capture the CO2 and other pollutants from the syngas. Once the CO2 is separated it can be transported to a disposal location.
In addition to adding the CO2 separation and capture equipment, changes in other components are also necessary for electricity generation case. The removal of CO2 prior to combustion in the turbine alters the composition of the gas to be burned, increasing the hydrogen content, which may affect the design or operational requirements of the turbine. In addition, the CO2 capture process may alter the optimal design of the desulphurization and other gas clean-up processes. For these reasons, an IGCC plant built without consideration for CO2 capture technology designed to produce power at a minimum cost and maximum efficiency will be significantly different than an IGCC plant designed to incorporate CO2 capture technology.
“Three major technological components need to be added to a basic IGCC plant to allow for separation and capture of the CO2: (1) the shift reactor to convert the CO in the syngas to CO2, (2) the process to separate the CO2 from the rest of the gas stream, and (3) a compressor to reduce the volume of separated CO2 before it can be transported.” Furthermore, other components will require modification, as previously mentioned, including the gas turbine that will have to be capable of operating with a hydrogen enriched gas stream, the timing of the sulphur removal process and some scaling up to accommodate the larger quantities of coal needed to generate the same amount of power.
A further consideration is the CO2 transportation and disposal. Once the CO2 is captured and compressed at the plant it must be transported and injected into an underground geologic formation. Therefore, the location of the plant can also become a significant factor in the ease of transformation.
What should be clear from this listing of requirements for integrating capture and disposal of CO2 into an existing IGCC plant is that the term “carbon capture ready” could encompass a whole host of definitions. Does it simply mean that one builds an IGCC plant? Does it mean that you leave space in the design for separation, capture and compression equipment? Does it mean you include the appropriate turbine to burn a high H2 gas stream? Does it mean you locate the plant within proximity to a geologic reservoir where the CO2 can be disposed of? The list and variations of the possibilities could go on and on, calling into question whether the term “carbon capture ready “ has any real meaning..
The likely result is that companies when taking advantage of the coal gasification incentives provided in the “Energy Policy Act of 2005” will follow the least cost option, i.e., build an IGCC plant with little or no design elements necessary for the future integration of CO2 capture and disposal -- unless there is a clear policy to reduce CO2 emissions or if it is required that they include all the necessary equipment to capture their CO2.
NRDC strongly advocates that all government funds that leverage the building of coal gasification plants should only go to those facilities that actually capture their CO2. Subsidizing gasification by itself wastes taxpayers’ money by subsidizing the wrong thing. Gasification is commercial and needs no subsidy but capture and storage is the primary policy objective and is likely to require subsidies pending adoption of CO2 emission control requirements.
The first proposed coal gasification plant that will capture and dispose of its CO2 was recently announced on February 10, 2006 by BP British Petroleum and Edison Mission Group. The plant will be built in Southern California and its CO2 emissions will be pipelined to an oil field nearby and injected into the ground to recover domestic oil. BP’s proposal shows the technologies are available now to cut global warming pollution and that integrated IGCC with CO2 capture and disposal are commercially feasible.
The Path Forward
The impacts that a large coal gasification program could have on global warming pollution, conventional air pollution and environmental damage resulting from the mining, processing and transportation of the coal are substantial. Before deciding whether to invest scores, perhaps hundreds of billions of dollars in deploying this technology, we must have a program to manage our global warming pollution and other coal related impacts. Otherwise we will not be developing and deploying an optimal energy system.
One of the primary motivators for moving toward coal gasification technologies has been to reduce natural gas prices. Fortunately, the U.S. can have a robust and effective program to reduce natural gas demand, and therefore prices, without rushing to embrace coal gasification technologies. A combination of efficiency and renewables can reduce our natural gas demand more quickly and more cleanly.
Implementing effective energy efficiency measures is the fastest and most cost effective approach to reducing natural gas demand. Efficiency standards, performance-based tax incentives, utility-administered deployment programs, and innovative market transformation strategies will bring energy efficient technologies to market and make efficient designs standard industry practice.
Renewable energy provides a critical mid-term to long-term supplement to natural gas use. Potential renewable resources in the U.S. are significant and renewable electricity generation is expanding rapidly, with wind and biomass currently offering the most cost-effective power in both countries. Some 20 U.S. states have adopted renewable portfolio standards requiring electricity providers to obtain a minimum portion of their portfolio from renewable resources. Federal tax incentives have also played an important role, particularly for wind.
With current coal (and oil) consumption trends, we are headed for a doubling of CO2 concentrations by mid-century if we don’t redirect energy investments away from carbon based fuels and toward new climate friendly energy technologies.
We have to accelerate the progress underway and adopt policies in the next few years to turn the corner on our global warming emissions, if we are to avoid locking ourselves and future generations into a dangerously disrupted climate. Scientists are very concerned that we are very near this threshold now. Most say we must keep atmosphere concentrations of CO2 below 450 parts per million, which would keep total warming below 2 degrees Celsius (3.6 degrees Fahrenheit). Beyond this point we risk severe impacts, including the irreversible collapse of the Greenland Ice Sheet and dramatic sea level rise. With CO2 concentrations now rising at a rate of 1.5 to 2 parts per million per year, we will pass the 450ppm threshold within two or three decades unless we change course soon.
In the United States, a national program to limit carbon dioxide emissions must be enacted soon to create the market incentives necessary to shift investment into the least-polluting energy technologies on the scale and timetable that is needed. There is growing agreement between business and policy experts that quantifiable and enforceable limits on global warming emissions are needed and inevitable. To ensure the most cost-effective reductions are made, these limits can then be allocated to major pollution sources and traded between companies, as is currently the practice with sulfur emissions that cause acid rain. Targeted energy efficiency and renewable energy policies are critical to achieving CO2 limits at the lowest possible cost, but they are no substitute for explicit caps on emissions.
A coal integrated gasification combined cycle (IGCC) power plant with carbon capture and disposal can also be part of a sustainable path that reduces both natural gas demand as well as global warming emissions in the electricity sector. Methods to capture CO2 from coal gasification plants are commercially demonstrated, as is the injection of CO2 into geologic formations for disposal. On the other hand, coal gasification to produce a significant amount of liquids for transportation fuel would not be compatible with the need to develop a low-CO2 emitting transportation sector. Finally, gasifying coal to produce synthetic pipeline gas or chemical products needs a careful assessment of the full life cycle emission implications and the emission reductions that are required from those sectors before decisions are made to invest in these systems.
In the absence of a program that requires limits on CO2 emissions IGCC systems with carbon capture and disposal will not be brought to market in time. We need to combine CO2 limits with financial incentives to start building these integrated plants now, because industry is already building and designing the power plants that we will rely on for the next 40-80 years.
To reduce our natural gas demand we should follow a simple rule: start with the measures that will produce the quickest, cleanest and least expensive reductions in natural gas use; measures that will put us on track to achieve the reductions in global warming emissions we need to protect the climate. If we are thoughtful about the actions we take, our country can pursue an energy path that enhances our security, our economy, and our environment.
Mining, Processing and Transporting Coal
The impacts of mining, processing, and transporting 1.1 billion tons of coal today on health, landscapes, and water are large. To understand the implications of continuing our current level of as well as expanding coal production, it is important to have a detailed understanding of the impacts from today’s level of coal production. The summary that follows makes it clear that we must find more effective ways to reduce these impacts before we follow a path that would result in even larger amounts of coal production and transportation.
Health and Safety
Coal mining is one of the U.S.’s most dangerous professions. The yearly fatality rate in the industry is 0.23 per thousand workers, making the industry about five times as hazardous as the average private workplace. The industry had 27 fatalities in 2002, an all-time low, and there were 55 deaths in 2004 and 57 deaths in 2005. The first month of 2006 was particularly deadly, however, with 18 fatalities through February 1st. Sixteen of these deaths occurred in West Virginia mines, leading the Governor to call for an unprecedented suspension of production while safety checks were conducted. Coal miners also suffer from many non-fatal injuries and diseases, most notably black lung disease (also known as pneumoconiosis) caused by inhaling coal dust. Although the 1969 Coal Mine Health and Safety Act seeks to eliminate black lung disease, the United Mine Workers estimate that 1500 former miners die of black lung each year.
Coal mining - and particularly surface or strip mining - poses one of the most significant threats to terrestrial habitats in the United States. The Appalachian region , for example, which produces over 35% of our nation’s coal , is one of the most biologically diverse forested regions in the country. But during surface mining activities, trees are clearcut and habitat is fragmented, destroying natural areas that were home to hundreds of unique species of plants and animals. Even where forests are left standing, fragmentation is of significant concern because a decrease in patch size is correlated with a decrease in biodiversity as the ratio of interior habitat to edge habitat decreases. This is of particular concern to certain bird species that require large tracts of interior forest habitat, such as the black-and-white warbler and black-throated blue warbler.
After mining is complete, these once-forested regions in the Southeast are typically reclaimed as grasslands, although grasslands are not a naturally occurring habitat type in this region. Grasslands that replace the original ecosystems in areas that were surface mined are generally categorized by less-developed soil structure and lower species diversity compared to natural forests in the region. Reclaimed grasslands are generally characterized by a high degree of soil compaction that tends to limit the ability of native tree and plant species to take root. Reclamation practices limit the overall ecological health of sites, and it has been estimated that the natural return of forests to reclaimed sites may take hundreds of years. According to the USEPA, the loss of vegetation and alteration of topography associated with surface mining can lead to increased soil erosion and may lead to an increased probability of flooding after rainstorms.
The destruction of forested habitat not only degrades the quality of the natural environment, it also destroys the aesthetic values of the Appalachian region that make it such a popular tourist destination. An estimated one million acres of West Virginia Mountains were subject to strip mining and mountaintop removal mining between 1939 and 2005. Many of these mines have yet to be reclaimed so that where there were once forested mountains, there now stand bare mounds of sand and gravel.
The terrestrial impacts of coal mining in the Appalachian region are considerable, but for sheer size they cannot compare to the impacts in the western United States. As of September 30, 2004, 470,000 acres were under federal coal leases or other authorizations to mine. Unlike the East, much of the West– including much of the region’s principal coal areas –is arid and predominantly unforested. In the West, as in the East, surface mining activities cause severe environmental damage as huge machines strip, rip apart and scrape aside vegetation, soils, wildlife habitat and drastically reshape existing land forms and the affected area’s ecology to reach the subsurface coal. Strip mining results in industrialization of once quiet open space along with displacement of wildlife, increased soil erosion, loss of recreational opportunities, degradation of wilderness values, and destruction of scenic beauty. Reclamation can be problematic both because of climate and soil quality. As in the East, reclamation of surface mined areas does not necessarily restore pre-mining wildlife habitat and may require scarce water resources be used for irrigation. Forty-six western national parks are located within ten miles of an identified coal basin, and these parks could be significantly affected by future surface mining in the region.
Coal production causes negative physical and chemical changes to nearby waters. In all surface mining, the overburden (earth layers above the coal seams) is removed and deposited on the surface as waste rock. The most significant physical effect on water occurs from valley fills, the waste rock associated with mountaintop removal (MTR) mining. Since MTR mining started in the United States in the early 70’s, studies estimate that over 700 miles of streams have been buried from valley fills, and 1200 additional miles have been directly impacted from valley fills through sedimentation or chemistry alteration. Together, the waterways harmed by valley fills are about 80 percent as long as the Mississippi River. Valley fills bury the headwaters of streams, which in the southeastern U.S. support diverse and unique habitats, and regulate nutrients, water quality, and flow quantity. The elimination of headwaters therefore has long-reaching impacts many miles downstream.
Coal mining can also lead to increased sedimentation, which affects both water chemistry and stream flow, and negatively impacts aquatic habitat. Valley fills in the eastern U.S., as well as waste rock from strip mines in the west add sediment to streams, as does the construction and use of roads in the mining complex. A final physical impact of mining on water is to the hydrology of aquifers. MTR and valley fills remove upper drainage basins, and often connect two previously separate aquifers, altering the surrounding groundwater recharge scheme.
Acid mine drainage (AMD) is the most significant form of chemical pollution produced from coal mining operations. In both underground and surface mining, sulfur-bearing minerals common in coal mining areas are brought up to the surface in waste rock. When these minerals come in contact with precipitation and groundwater, an acidic leachate is formed. This leachate picks up heavy metals and carries these toxins into streams or groundwater. Waters affected by AMD often exhibit increased levels of sulfate, total dissolved solids, calcium, selenium, magnesium, manganese, conductivity, acidity, sodium, nitrate, and nitrite. This drastically changes stream and groundwater chemistry. The degraded water becomes less habitable, non potable, and unfit for recreational purposes. The acidity and metals can also corrode structures such as culverts and bridges. In the eastern U.S., estimates of the damage from AMD range from four to eleven thousand miles of streams. In the West, estimates are between five and ten thousand miles of streams polluted. The effects of AMD can be diminished through addition of alkaline substances to counteract the acid, but recent studies have found that the addition of alkaline material can increase the mobilization of both selenium and arsenic. AMD is costly to mitigate, requiring over $40 million annually in Kentucky, Tennessee, Virginia, and West Virginia alone.
There are two main sources of air pollution during the coal production process. The first is methane emissions from the mines. Methane is a powerful heat-trapping gas and is the second most important contributor to global warming after carbon dioxide. Methane emissions from coal mines make up between 10 and 15% of anthropogenic methane emissions in the U.S. According to the most recent official inventory of U.S. global warming emissions, coal mining results in the release of 3 million tons of methane per year, which is equivalent to 68 million tons of carbon dioxide.
The second significant form of air pollution from coal mining is particulate matter (PM) emissions. While methane emissions are largely due to eastern underground mines, PM emissions are particularly serious at western surface mines. The arid, open and frequently windy region allows for the creation and transport of significant amounts of particulate matter in connection with mining operations. Fugitive dust emissions occur during nearly every phase of coal strip mining in the west. The most significant sources of these emissions are removal of the overburden through blasting and use of draglines, truck haulage of the overburden and mined coal, road grading, and wind erosion of reclaimed areas. PM emissions from diesel trucks and equipment used in mining are also significant. PM can cause serious respiratory damage as well as premature death. In 2002, one of Wyoming’s coal producing counties, Campbell County, exceeded its ambient air quality threshold several times, almost earning non-attainment status. Coal dust problems in the West are likely to get worse if the administration finalizes its January 2006 proposal to exempt mining (and other activities) from controls aimed at meeting the coarse PM standard.
Coal Mine Wastes
Coal mining leaves a legacy of wastes long after mining operations cease. One significant waste is the sludge that is produced from washing coal. There are currently over 700 sludge impoundments located throughout mining regions, and this number continues to grow. These impoundment ponds pose a potential threat to the environment and human life. If an impoundment fails, the result can be disastrous. In 1972 an impoundment break in West Virginia released a flood of coal sludge that killed 125 people. In the year 2000 an impoundment break in Kentucky involving more than 300 million gallons of slurry (30 times the size of the Exxon Valdez spill) killed all aquatic life in a 20 mile diameter, destroyed homes, and contaminated much of the drinking water in the eastern part of the state.
Another waste from coal mining is the solid waste rock left behind from tunneling or blasting. This can result in a number of environmental impacts previously discussed, including acid mine drainage (AMD). A common problem with coal mine legacies is the fact that if a mine is abandoned or a mining company goes out of business, the former owner is under no legal obligation to cleanup and monitor the environmental wastes, leaving the responsibility in the hands of the state.
Effects on Communities
Coal mining can also have serious impacts on nearby communities. In addition to noise and dust, residents have reported that dynamite blasts can crack the foundations of homes , and many cases of subsidence due to the collapse of underground mines have been documented. Subsidence can cause serious damage to houses, roads, bridges, and any other structure in the area. Blasting can also cause damage to wells, and changes in the topography and structure of aquifers can cause these wells to run dry.
Transportation of Coal
Transporting coal from where it is mined to where it will be burned also produces significant quantities of air pollution and other environmental harms. Diesel-burning trucks, trains, and barges that transport coal release NOx, SOx, PM, VOCs (Volatile Organic Chemicals), CO, and CO2 into the earth’s atmosphere. Trucks and trains (barge pollution data are unavailable) transporting coal release over 600,000 tons of NOx, and over 50,000 tons of PM10 into the air annually. , In addition to health risks, black carbon from diesel combustion is another contributor to global warming. Land disturbance from trucks entering and leaving the mine complex and coal dust along the transport route also release particles into the air. For example, in Sylvester, West Virginia, a Massey Energy coal processing plant and the trucks associated with it spread so much dust around the town that “Sylvester’s residents had to clean their windows and porches and cars every day, and keep the windows shut.” Even after a lawsuit and a court victory, residents – who now call themselves “Dustbusters” – still “wipe down their windows and porches and cars.”
Almost 60 percent of coal in the U.S. is transported at least in part by train and coal transportation accounts for 44% of rail freight ton-miles. Some coal trains reach more than two miles in length, causing railroad-crossing collisions and pedestrian accidents (there are approximately 3000 such collisions and 900 pedestrian accidents every year), and interruption in traffic flow (including emergency responders such as police, ambulance services, and fire departments). Local communities also have concerns about coal trucks, both because of their size and the dust they can leave behind. According to one report, in a Kentucky town, coal trucks weighing 120 tons with their loads were used, and “the Department of Transportation signs stating a thirty-ton carrying capacity of each bridge had disappeared.” Although the coal company there has now adopted a different route for its trucks, community representatives in Appalachia believe that coal trucks should be limited to 40 tons.
Coal is also sometimes transported in a coal slurry pipeline, such as the one used at the Black Mesa Mine in Arizona. In this process the coal is ground up and mixed with water in a roughly 50:50 ratio. The resulting slurry is transported to a power station through a pipeline. This requires large amounts of fresh groundwater. To transport coal from the Black Mesa Mine in Arizona to the Mohave Generating Station in Nevada, Peabody Coal pumped over one billion gallons of water from an aquifer near the mine each year. This water came from the same aquifer used for drinking water and irrigation by members of the Navajo and Hopi Nations in the area. Water used for coal transport has led to a major depletion of the aquifer, with more than a 100 foot drop in water level in some wells. In the West, coal transport through a slurry pipeline places additional stress on an already stressed water supply. Maintenance of the pipe requires washing, which uses still more fresh water. Not only does slurry-pipeline transport result in a loss of freshwater, it can also lead to water pollution when the pipe fails and coal slurry is discharged into ground or surface water. The Peabody pipe failed 12 times between 1994 and 1999. The Black Mesa mine closed as of January 2006. Its sole customer, the Mohave Generating Station, was shut down because its emissions exceeded current air pollution standards.