EIA Analyzes Power Sector Emissions Factors

Source: U.S. Energy Information Administration, Monthly Energy Review, September 2013, and the Annual Energy Outlook 2014
Note: GHG is greenhouse gases. The GHG10 case assumes a $10 per metric ton fee on CO₂ emissions, beginning in the year 2015. The GHG25 assumes a $25 per metric ton fee on CO₂ emissions beginning in 2015. Both cases escalate the CO₂ fee at a rate of 5% per year. The GHG10 case with low natural gas prices combines the assumptions of the GHG10 case with the High Oil and Gas Resource case, which results in lower gas prices and encourages greater natural gas use.

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In 2012, almost 40% of total energy-related CO₂ emissions resulted from electricity generation. About three-fourths of those power sector emissions occurred from burning coal, the most carbon-intensive fuel. Policies to reduce CO₂ emissions could result in less consumption of coal in favor of natural gas, which emits about 40% as much CO₂ per kilowatthour as typical coal-fired generation when used in a combined-cycle plant, as well as increases in other low- or zero-carbon power generating technologies such as renewables and nuclear.

Earlier this week, the Environmental Protection Agency (EPA) issued a proposed rule  that would require reductions in CO₂ emissions from existing fossil-fueled electric power plants. The EPA proposal includes emission rate targets for each state, measured as pounds of CO₂ emissions per megawatthour of covered generation, as well as guidelines for the development, submission, and implementation of state plans. The emission rate targets vary significantly across individual states, reflecting the application of a series of common building blocks to states with widely different starting points in their respective electricity markets.

The Annual Energy Outlook 2014 (AEO2014) Reference case, which assumes current laws and regulations, does not include the EPA proposal. Currently there are two regional programs in the Northeast and California (the Regional Greenhouse Gas Initiative and Assembly Bill 32, known as RGGI and AB32, respectively) that include control policies for greenhouse gases (GHGs) from the power industry, which are also included in the AEO2014 Reference case. All existing final environmental rules, including the Mercury and Air Toxics Standard, are also included in the projections. After taking these existing environmental regulations into account, the projections for electricity generation and its resulting emissions are primarily determined by the relative operating costs of the different technologies. The AEO2014 Reference case projections show several CO₂-related trends, including:

• CO₂ emissions from the electric power sector increase from 2,035 million metric tons in 2012 to 2,271 million metric tons in 2040, an increase of 12%
• The share of power sector CO₂ emissions from natural gas increases from 24% to 27%, as natural gas-fired plants account for most of the capacity that is added to meet increases in demand and to replace retiring plants
• Few new coal plants are added, as uncertainty about future carbon regulations influences capacity decisions

While EIA does not assume the final structure of any proposed regulations, in order to represent policies that explicitly or implicitly place a value on GHG emissions, the AEO2014 includes alternative cases that impose a fee on energy-related CO₂ emissions. These side cases incorporate an initial CO₂ value of $10 (GHG10 case) and $25 (GHG25 case) per metric ton in 2015, rising by 5% per year. The GHG10 case is also combined with High Oil and Gas Resources, which results in lower gas prices and encourages greater natural gas use. In these side cases, EIA projects the following results as compared with the AEO2014 Reference case:

• 2025 power sector CO₂ emissions are 16% and 49% lower in the GHG10 and GHG25 cases with fees, respectively, and 23% lower when the GHG10 case is combined with the High Oil and Gas Resource case
• 2040 power sector CO₂ emissions reductions range from 36% to 82% across the three side cases, which is greater than the corresponding changes in other sectors and indicates that the electric power industry is typically the most cost effective sector to achieve reductions in response to economy-wide CO₂fees
• Natural gas-fired generation increases sharply beginning when CO₂ fees are assumed to be introduced in 2015, followed by more nuclear and renewable plant additions as the fees increase
• Natural gas-fired generation levels off around 2030 in the GHG10 case, and it begins to decline after 2025 in the GHG25 case
• In the High Oil and Gas Resource case without CO₂ fees, lower natural gas prices result in higher gas-fired generation and CO₂ emissions in the power sector as more new natural gas plants are built instead of nuclear and renewable capacity
• Natural gas-fired generation continues to increase through 2040 when the fees for the GHG10 case are combined with the lower gas prices from the High Oil and Gas Resource case

Source: U.S. Energy Information Administration, Monthly Energy Review, September 2013, and the Annual Energy Outlook 2014

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Additional analysis can be found in the AEO2014 Market Trends discussion of emissions from energy use.

EIA Updates U.S. Emissions Trends

Source: U.S. Energy Information Administration, State Energy Data System (SEDS) 2014

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U.S. energy-related carbon dioxide (CO₂) emissions in 2013 were 10% below the benchmark year of 2005. Emissions in 2013 were roughly 2% above their 2012 level and 1.5% below their 2011 level, when emissions were 8.6% below the 2005 level. Recently released state-level data through 2011, calculated from the State Energy Data System (SEDS) and aggregated here by Census regions, show different parts of the country generally experiencing this downward trend, but at variable rates by region.

Between 2005 and 2011, all four Census regions—West, South, Midwest, and Northeast—experienced emissions declines, with the Northeast experiencing larger emissions reductions than the other regions. Underlying state-level emissions changes spanned an even wider range, from a 20% emissions increase in Nebraska (Midwest) to a 33% decrease in Nevada (West). Regional and subregional spreads reflect differences in local energy economics, population distribution, and other factors.

Source: U.S. Energy Information Administration, State Energy Data System (SEDS) 2014

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Drivers of faster, larger emissions declines in the Northeast include extensive urbanization, translating into denser, more energy-efficient population centers, and increasingly low-carbon electricity generation from natural gas, nuclear, and renewables, instead of coal. The Northeast includes the top-three lowest emitting states per unit of economic output (New York, Connecticut, and Massachusetts) and two of the top-five states with the cleanest electricity sources (Vermont and New Hampshire).

Compared to the Northeast, the other regions (Midwest, West, and South) have more diverse state-level characteristics, which contributed to relatively slower net emissions declines. Steep emissions reductions in some states were partially offset by escalating emissions elsewhere. For example, states like Wyoming (West), North Dakota (Midwest), and West Virginia (South) have more carbon-intensive energy production, higher and less efficient energy use in more sparsely populated areas, and heavily coal-reliant electricity generation compared to other states in those regions. Since 2009, factors driving the uptick in Nebraska's emissions profile included marked expansion of the biofuels (corn-based ethanol) industry, as well as increased production of crude oil and the temporary closure of the Fort Calhoun nuclear power plant. Conversely, Nevada's lower-bounding trend shows the effects of substantially decarbonizing its electric power sector—between 2005 and 2011, Nevada significantly reduced its coal use, while increasing solar and geothermal use.

Earlier this week, the Environmental Protection Agency (EPA) issued a proposed rule that would require reductions in carbon dioxide emissions from existing fossil-fueled electric power plants. The EPA proposal includes emission rate targets for each state, measured as pounds of carbon dioxide emissions per megawatthour of covered generation, as well as guidelines for the development, submission, and implementation of state plans. The emission rate targets vary significantly across individual states, reflecting the application of a series of common building blocks to states with widely different starting points in their respective electricity markets.

Source: EIA

Effect of Power Plant Closures on CO2 Emissions

Source: U.S. Energy Information Administration, Annual Energy Outlook 2014, Issues in Focus

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Significant retirements of nuclear and coal power plants in the United States could change the amount of carbon dioxide (CO₂) emitted by the electric power sector. EIA's Annual Energy Outlook 2014 (AEO2014) features several accelerated retirements cases that represent conditions leading to additional coal and nuclear plant retirements in order to examine the potential energy market and emissions effects of the loss of this capacity. CO₂ emissions are significantly reduced when compared to the Reference case in side cases with accelerated coal retirements. CO₂ emissions increase slightly in the Accelerated Nuclear Retirements case. Natural gas and renewables are the primary replacements for lost capacity in each scenario.

Source: EIA

EIA Releases 2013 U.S. CO2 Emissions Estimate

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2014

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Once all data are in, energy-related carbon dioxide (CO₂) emissions in 2013 are expected to be roughly 2% above the 2012 level, largely because of a small increase in coal consumption in the electric power sector. Coal has regained some market share from natural gas since a low in April 2012; however the impact on overall emissions trends remains fairly small.

Emissions in 2013 are slightly more than 10% below 2005 levels, a significant contribution towards the goal of a 17% reduction in emissions from the 2005 level by 2020 that was adopted by the current Administration. This level of reduction is expected to continue through 2015, according to EIA's most recent Short-Term Energy Outlook.

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2014

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CO₂ emissions from energy activities declined four out of six years since their 2007 peak, and were historically low (12% below the 2005 level) in 2012. From 2005 to 2013, the key energy-economic drivers of a changing U.S. energy landscape included:

• Weak economic growth in recent years, dampening growth in energy demand compared to pre-recession expectations
• Continuously improving energy efficiency across the economy, including buildings and transportation
• High energy prices over the past four years, with the exception of natural gas, since about 2010
• An abundant and inexpensive supply of natural gas, resulting from the widespread use of new production technologies for shale gas
• Power sector decarbonization since 2010, as natural gas and renewables displaced coal

Source: EIA

Alberta's CCEMC Releases Annual Report

EDMONTON – The Alberta-based Climate Change and Emissions Management (CCEMC) Corporation released its 2012/2013 annual report that features 12 new renewable energy and energy efficiency projects. In total, the CCEMC now supports 51 clean tech projects with $212.8 million in committed funding. More

Illinois CCS Update

In an update on its carbon capture project at an ethanol plant near Decatur, Illinois, Archer Daniels Midland Co. says it has captured 685,000 metric tons of carbon emissions and stored them underground storage in the past two years. Carbon dioxide injections began in November 2011 at a rate of about 1,000 tons a month and are expected to continue through next year when the project is expected to reach the permitted level of 1 million tones. 

The project at the Decatur plant is among the largest CCS experiments in the country. The purpose is to test the storage potential of the Mount Simon Sandstone and the integrity of the overlying sealant rocks. Decatur was initially selected in October 2009 for the DOE Phase 1 research and development grants. Following successful completion of the Phase 1 activities, it was identified as one of the most promising industrial CCS projects through a competitive process and entered into Phase 2 with additional funding to begin design, construction, and operation.

Drilling began in February 2009 and a successful injection with a rate of 1000 tons per day was achieved in September 2009. 3D seismic surveys of the injection zone were completed in March 2010 in preparation for Phase 2.

Construction activities began at Decatur on August 26, 2011 with injection commencing in November 2011. As of April 2012, the project has successfully stored over 110,000 tons of CO2. In September 2012, the DOE marked 2 major milestones for the Decatur CCS project: The construction on the project’s storage facility, as well as the public opening of the National Sequestration Education Center. In November 2012 Decatur project completed its first year of CO2 injection operations with a total of 317,000 tons having been buried at a rate of 1,100 tons/day.

The target formation, the Mount Simon Sandstone, was selected as the optimum saline sink because of its widespread nature and immediately overlying Eau Claire shale seal. The Mount Simon Sandstone also underlies one of the largest concentrations of coal fired power plants in the world. This makes the Mount Simon Sandstone one of the most significant carbon storage resources in the United States.

Archer Daniels Midland (June 2010) was selected to receive an additional $99 million in federal aid to help fund a second carbon sequestration project for which the company is awaiting regulatory approval. The goal is to store 1 million tons of CO2 per year for five years. The company hopes to begin the second project in early 2015.

Read more

Using CO2 to Produce Geothermal Energy

SAN FRANCISCO - Researchers are developing a new kind of geothermal power plant that will lock away unwanted carbon dioxide (CO2) underground and use it as a tool to boost electric power generation by at least 10 times compared to conventional geothermal power.

The technology for this design already exists in different industries, and the researchers, led by Tom Buscheck, earth scientist from Lawrence Livermore National Laboratory, are hopeful that their new approach to the technology will expand the use of geothermal energy in the U.S. far beyond the small handful of states that can take advantage of it now. Heat Mining Company, LLC, a startup spun off from the University of Minnesota, expects to have an operational project based on an earlier form of this new approach in 2016.

At the American Geophysical Union meeting on Friday, Dec. 13, Buscheck and his colleagues fromThe Ohio State University, the University of Minnesota and Lawrence Livermore, will debut an expanded version of the design and explain the role that this new approach to geothermal energy production and grid-scale energy storage can have in addressing climate change.

The new power plant design resembles a cross between a geothermal plant and the Large Hadron Collider: it features a network of subsurface concentric rings of horizontal wells inside which CO2, nitrogen and water circulate to draw heat from deep below ground up to the surface, where it can be used to turn turbines and generate electricity.

"This well arrangement encircles the injected fluids with a subsurface hydraulic dam, functioning much like a hydroelectric dam. The intent is to recover the maximum energy benefit from fluid injection operations, a major improvement over conventional geothermal power systems," Buscheck noted.

The design contrasts with conventional geothermal plants in a number of important ways, explained study co-principal investigator Jeffrey Bielicki, assistant professor of energy policy in the Department of Civil, Environmental and Geodetic Engineering at The Ohio State University.

"Typical geothermal power plants tap into hot water that is deep underground,pull the heat off the hot water, use that heat to generate electricity and then return the cooler water back to the deep subsurface. Here the water is partly replaced with CO2 and/or another fluid," he said.

"Tt that there are benefits to using CO2, because it mines heat from the subsurface more efficiently than water," he continued."This combined approach (originally developed by Martin Saar at the University of Minnesota) can be at least twice as efficient as conventional geothermal approaches, and expand the reach of geothermal energy in the United States to include most states west of the Mississippi River."

The research team used computer simulations to design the system. In the simulations, a system of four concentric rings of horizontal wells about three miles below ground, with the outer ring being a little more than 10 miles in diameter, produced as much as a half a gigawatt of electrical power - an amount comparable to a medium-sized coal-fired power plant, and more than 10 times bigger than the 38 megawatts produced by the average geothermal plant in the U.S.

The simulations also revealed that a plant of this design might sequester as much as 15 million tons of CO2 per year, which is roughly equivalent to the amount produced by three medium-sized coal-fired power plants in that time.

"One of our key objectives when we began developing the CO2 plume geothermal technology was to find a way to help make CO2 storage cost effective while expanding the use of geothermal energy," said Jimmy Randolph, postdoctoral researcher in the Department of Earth Sciences at the University of Minnesota.

During the past year,  Buscheck added another gas - nitrogen - to the mix, resulting in a design that he and his colleagues believe will enable highly efficient energy storage at an unprecedented magnitude (at least hundreds of gigawatt hours) and unprecedented duration (days to months), provide operational flexibility, and lower the cost of renewable power generation.

"Nitrogen has several advantages," Buscheck explained. "It can be separated from air at lower cost than captured CO2, it's plentiful, it's not corrosive and will not react with the geologic formation in which it is being injected. And because nitrogen is readily available, it can be injected selectively. Thus, much of the energy required to drive the hot fluids out of the deep subsurface to surface power plants can be shifted in time to coincide with minimum power demand or when there is a surplus of renewable power on the electricity grid.

The distribution of stored nitrogen in the underground geothermal reservoir system is shown after 10 years of energy storage and production operations.

"Because we are storing energy in the form of pressurized fluids, we can further improve on this concept by selectively producing hot fluids when power demand is high, as well as reduce or stop that production when power demand is low. What makes this concept transformational is that we can deliver renewable energy to customers when it is needed, rather than when the wind happens to be blowing, or when spring thaw causes the greatest runoff."

The technology could possibly be used to expand the use of geothermal energy around the country. Right now, most geothermal power plants are in California and Nevada, where an especially strong geothermal gradient heats water underground. But the new design is so much more efficient at extracting heat that even smaller-scale "hotspots" throughout the western U.S. could generate power. (The eastern U.S. is mostly devoid of even small hotspots, so geothermal power would still be limited to a few particularly active areas such as West Virginia, Bielicki said.)

Another caveat: the geothermal plant would probably have to be connected to a large CO2 source, such as a coal-fired power plant, which was scrubbing the CO2 from its own emissions. That connection would likely be made by pipeline. Buscheck added, however, that a pilot plant based on this design could initially be powered solely by nitrogen injection, in order to prove the economic viability of using CO2. The study also showed that this design can work effectively with or without CO2, broadening where this approach could be deployed. The research team is currently working on more detailed computer model simulations and economic analyses for specific geologic settings in the U.S.

Co-authors on the presentation included Mingjie Chen, Yue Hao, Yunwei Sun, all of Lawrence Livermore. Work at the University of Minnesota and The Ohio State University is funded by the National Science Foundation, while work at Lawrence Livermore National Laboratory is funded by the U.S. Department of Energy's Office of Energy Efficiency and Renewable Energy. 

Source: Lawrence Livermore National Laboratory

EPA Issues Final Rule for CO2 Storage

The U.S. Environmental Protection Agency (EPA) has issued a final rule governing the geologic sequestration of carbon dioxide. Under the new rule, captured CO2 injected into wells that meet the conditions established for that purpose will not be subject to EPA's regulations for hazardous waste. In addition, the EPA will exempt CO2 injected for enhanced oil recovery from hazardous waste regulations. The rule will take effect 60 days after it is published in the Federal Register. Members of the public and interested parties have 75 days to comment on the guidance. More

Update - C02 Emissions by Large Corporations

According to a Reuters report published this week, the majority of large global corporations that regularly report their annual greenhouse gas emissions are still releasing unsustainable levels of carbon dioxide and are not setting their emissions targets and reduction policies on science-based thresholds. The report was based on a study by the U.S.-based Climate Counts, an organization that measures the role corporations play on climate. The research used data from 100 companies in ten different sectors. More

Ocean Floor CO2 Storage Sites Identified

A British research team at the University of Southampton team reportedly has investigated the properties of CO2 and created global maps of the ocean floor to determine where the greenhouse gas could be safely stored.  By estimating temperatures in the upper ocean crust, the team was able to identify where it may be possible to store large volumes of CO2 in the basalts in the stable liquid form. Among the five suitable regions are sites off the coast of Australia, Japan, Siberia, South Africa and Bermuda, ranging in size from ½ million square kilometres to almost four million square kilometres. More

SaskPower CO2 Capture Project Update

Hitachi today announced that construction has begun on a Carbon Capture Test Facility ("CCTF") designed to capture CO2 emissions from coal-fired power plants. Hitachi and its partner, Saskatchewan Power Corporation ("SaskPower"), agreed to build this demonstration project in March of 2012. The construction work is expected to be completed during the fall of 2014, and the CCTF will be operational by the end of that year. The goal of the demonstration project is to determine the necessary properties required to scale up to a large, commercial-size facility, and demonstration tests will be conducted to comprehensively evaluate the facility's overall reliability and economic feasibility.
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World Energy Ministers Endorse CCS

Washington, D.C. — Energy and environment ministers from the Carbon Sequestration  Leadership Forum’s (CSLF) member nations today endorsed carbon capture and storage  technologies (CCS) as a key component of international plans to combat climate change. Their endorsement at a high-level meeting here is viewed as affirmation that carbon capture and storage must be an integral component of any international plan to combat climate change.

In a Communiqué released following day-long discussions, CSLF member country Ministers and  Heads of Delegation affirmed that CCS is an indispensable element of any effective response to  climate change. The Ministers stressed “we are convinced that the demonstration and global deployment of carbon capture and storage must be accelerated and we are committed to taking necessary actions individually and collaboratively to make this happen.”

CCS is a group of technologies for capturing carbon dioxide (CO2), a major greenhouse gas, emitted by power plants or industrial facilities and safely injecting it deep underground into suitable, permanent geologic storage sites. It is increasingly viewed by international experts as an essential part of a portfolio of responses by the world to effective management and reduction of human-based CO2 emissions.

Forum membership spans the world's largest blocs of economic activity, including the North  America Free Trade Area, the European Union and the leading economies of Asia. Members are Australia, Brazil, Canada, China, the European Commission, France, Germany, Greece, India, Italy, Japan, Mexico, the Netherlands, New Zealand, Norway, Poland, Russia, Saudi Arabia, South Africa, South Korea, United Arab Emirates, the United Kingdom and the United States.

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SaskPower Releases Aquistore Update

Following recent media coverage, SaskPower has today confirmed to PTRC that it remains fully committed to the Aquistore project, and the research and monitoring program managed by PTRC.

The installation of wells and other infrastructure at the Aquistore site cost approximately 15% more than predicted, owing to technical factors including the unexpected depth of the wells and complications with the cementing of the second well. The safety of the wells remained an absolute priority during site works. Consequently, the project has a current net deficit of $3m, as reported by PTRC. The Aquistore project recorded a deficit of $5.9m during the 2012/3 financial year, but this figure does not allow for committed funding that is due for future payment.

With the transfer of site infrastructure to SaskPower ahead of injection operations, and with future funding opportunities, PTRC has complete confidence that the research and monitoring program will be completed in 2017 as planned.

The Aquistore project offers PTRC another outstanding research opportunity, building on the success of the IEAGHG Weyburn-Midale project, and we are proud to support SaskPower’s ground breaking CCS project at Boundary Dam.

Source: Aquistore

Texas CCUS Project Officially Up and Running

WASHINGTON — The Energy Department’s Acting Assistant Secretary for Fossil Energy Christopher Smith attended last week's dedication ceremony at the Air Products and Chemicals hydrogen production facilities in Port Arthur, Texas. Supported by a $284 million Energy Department investment, the company has successfully begun capturing carbon dioxide from industrial operations and is now using that carbon for enhanced oil recovery (EOR) and securely storing it underground. This first-of-a-kind, breakthrough project advances carbon capture, utilization and storage technologies and demonstrates the potential to safely secure carbon dioxide pollution underground while providing an economic benefit and increasing our energy security.

At full-scale operation, more than 90 percent of the carbon dioxide from the product stream of two methane steam reformers — or approximately one million metric tons of carbon dioxide per year — will be delivered for sequestration and EOR, which will lead to an estimated annual increase in oil production of 1.6 to 3.1 million barrels from the West Hastings oil field located about 20 miles south of Houston, Texas.

“The Energy Department is investing in cutting-edge technologies that will help us safely and more sustainably develop all of America’s rich energy resources,” said Acting Assistant Secretary for Fossil Energy Christopher Smith. “This groundbreaking project demonstrates the potential to produce economic benefits and increase our energy security while greatly reducing the environmental impacts of our fossil energy use.”

The two retrofitted Air Products and Chemicals plants produce commercial bulk hydrogen primarily for use at the nearby Valero refinery. The approximately $431 million project, supported by $284 million from the Energy Department, included retrofitting the plants with an innovative system that separates carbon dioxide from the steam reformer product gas during hydrogen production, followed by compression and drying processes. The Energy Department investment also helped construct a 13.1-mile-long feeder that connects the two plants to an existing 325-mile, 24-inch carbon dioxide pipeline, Denbury’s Green Pipeline, that begins in Louisiana and ends at the West Hastings field. Careful carbon dioxide monitoring, verification, and accounting activities to ensure the injected carbon dioxide remains in the underground geologic formation will take place throughout the lifetime of the project.

The first plant has been capturing carbon dioxide since December 2012, while the second plant completed construction in February and began carbon capture operations in March.  Both units are now operating at full capacity.  Over 222,000 tons of carbon dioxide have been captured and provided for storage as of early May.

The Port Arthur project is part of the Energy Department’s broader efforts to leverage cutting-edge research to show that not only can Carbon Capture and Storage (CCS) technology help industry make fossil energy use cleaner, safer and more sustainable, it also shows promise as a method to extract more, hard-to-access and presently untapped fossil energy resources. By putting the captured carbon dioxide to use, Carbon Capture, Utilization and Storage (CCUS) provides an additional business and market case for companies to pursue the environmental benefits of CCS.

To learn more about CCUS, watch the short video HERE

Source: NETL

CO2 Emissions from U.S. Energy Sources Decline

Source: U.S. Energy Information Administration

 

Source: U.S. Energy Information Administration, Monthly Energy Review
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Energy-related carbon dioxide (CO₂) emissions in 2012 were the lowest in the United States since 1994, at 5.3 billion metric tons of CO₂ (see figure above). With the exception of 2010, emissions have declined every year since 2007.

The largest drop in emissions in 2012 came from coal, which is used almost exclusively for electricity generation (see figure below). During 2012, particularly in the spring and early summer, low natural gas prices led to competition between natural gas- and coal-fired electric power generators. Lower natural gas prices resulted in reduced levels of coal generation, and increased natural gas generation—a less carbon-intensive fuel for power generation, which shifted power generation from the most carbon-intensive fossil fuel (coal) to the least carbon-intensive fossil fuel (natural gas).

Other factors contributing to the lower emissions include decreased demand for transportation fuels and mild winter temperatures that reduced demand for heating. The warm winter months during 2012 (particularly in the first quarter) more than offset a slight increase in cooling degree days during the summer months. EIA recently published preliminary data for January-December 2012 in the March 2013 edition of the Monthly Energy Review, which includes statistics covering all aspects of energy. EIA will publish a full analysis of 2012 energy-related CO₂ emissions later this year.

 

Source: U.S. Energy Information Administration, Monthly Energy Review
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NETL Releases Data on Methane Hydrate Test

Washington, D.C. —Data from an innovative test conducted last year that used carbon dioxide (CO₂) and nitrogen (N₂) injection to release natural gas from methane hydrates at a well on the Alaska North Slope is now available to researchers and the public on the National Energy Technology Laboratory (NETL) website.

Methane hydrate - essentially molecules of natural gas trapped in ice crystals - represents a potentially enormous energy resource, possibly exceeding the combined energy content of all other fossil fuels. Hydrate resources in arctic sandstone reservoirs contain an in-place gas volume estimated to be in the 100’s of trillions of cubic feet (TCF), while hydrate in marine sands is estimated to contain 1,000’s to 10,000’s of TCF, and hydrate dispersed through marine mud is estimated to contain 100,000’s of TCF. In addition to the immense resource, CO₂ injection into methane hydrate deposits is a technology that can potentially both release an energy resource while permanently storing carbon dioxide, a major greenhouse gas.

The U.S. Department of Energy (DOE), in partnership with other nations and industry, has played a leading role in developing technologies to evaluate how to safely recover these methane hydrate energy resources in order to provide new supplies of clean-burning natural gas.  These resources occur in a variety of forms in sediments within and below thick permafrost in Arctic regions, and in the subsurface of continental waters with a depth of 1,500 feet or greater.  The U.S. Geological Survey (USGS) has estimated a potentially recoverable resource of 85 trillion cubic feet of gas in favorable hydrate accumulations on the Alaska North Slope alone. 

NETL, the research laboratory of DOE’s Office of Fossil Energy (FE), participated in gas hydrate field production trials in early 2012 in partnership with ConocoPhillips and the Japan Oil, Gas and Metals National Corp. (JOGMEC). This test well (known as Iġnik Sikumi, Inupiat for “Fire in the Ice”) represented the first test of a CO₂ exchange technology that was developed by ConocoPhillips and the University of Bergen, Norway.  In the test, a small volume of CO₂ and nitrogen was injected into the well and then the well was produced back to demonstrate that this mixture of injected gases could promote production of natural gas.

The large volumes of raw data from the test are currently under evaluation.  The data now available from the test program include the rates and composition of gases both injected and produced, and information on changes in the reservoir pressure and temperature during the test. ConocoPhillips has further augmented the raw data through extensive quality control checks and integration of the various measurements to a standard time framework.  The data are now fully available to all researchers and the public for analysis and evaluation. 

Both the U.S. and Japan have committed to utilizing Arctic gas hydrate research opportunities as an important step in assessing the potential for gas hydrate production in deepwater marine settings, the location of the vast majority of global resources.  DOE and JOGMEC have also collaborated on the development of specialized core sampling devices through the Gulf of Mexico Gas Hydrates Joint Industry Project (an industry consortium managed by Chevron) conducting research on deepwater gas hydrate characterization technology.

In addition to the U.S./Japan collaboration, FE scientists have worked actively with researchers in Korea, India, China, Canada and other nations, as well as with USGS, the Bureau of Ocean Energy Management (BOEM), and other federal agencies, to advance methane hydrate technology.  The Methane Hydrate Research and Development Act of 2000 established DOE (through the efforts of FE and NETL) as the lead U.S. agency for methane hydrate research and development.

Source: NETL

Granada Scientists Announce New Carbon Gel

Scientists at the University of Granada (UGR) claim they have invented a carbon gel that enables CO2 to be turned into hydrocarbons by electro-catalytic transformation. The doped carbon gel made up of 90% carbon and a small quantity of heavy metals acts as a highly-dispersed and effective electro-catalyst, which means it enables CO2 to be turned into hydrocarbons at a low cost, according to a university press release. The new material was developed entirely at the UGR following more than 10 years of research into carbon gels and has recently been patented by the Institution’s Office for the Transfer of Research Results. Read more

CPI to Host Webinar on Emissions Tracking

National governments use a wide range of institutions and processes to measure, report, and verify (MRV) emissions and mitigation outcomes. These tracking systems are a critical component of policy effectiveness — they help countries meet their domestic policy objectives by tracking achievement of domestic policy targets and informing future policy decisions. Effective domestic MRV processes can also build trust among nations, provide confidence in the effectiveness of international agreements, and inform the design of such agreements.

The Climate Policy Initiative (CPI) has engaged in an effort to characterize, evaluate, and draw insights from domestic MRV systems in four of the major emitters — China, Germany, Italy, and the United States. In a webinar planned for March 12, CPI will highlight the institutional processes these countries use to track emissions and mitigation actions, assess how well they’re currently performing, and point out where systems need to be strengthened in order to meet emerging needs.

NETL Updates Membrane CO2 Capture Research

Membranes offer a potential low-maintenance and economical method for gas separations from power plant flue gas streams. Polymer membranes and supported liquid membranes show great promise to solve problems in the area of clean energy production. Carbon dioxide, a greenhouse gas, is a principal by-product of energy production from fossil fuels. Capturing CO₂ from power plant flue gas streams is critical to the goal of reducing the nation’s carbon footprint and preserving the environment. Currently, there is no technology that can meet the goals for carbon capture as set forth by the U.S. Department of Energy. These goals are 90% capture of the CO₂with a less than 35% increase in the cost of energy.

The National Energy Technology Laboratory (NETL) is pursuing the development of both polymeric and supported ionic liquid membranes for CO₂ capture. Development of adequate membrane technology requires equipment capable of rapidly measuring membrane performance. Typical membrane testing equipment operates under either constant pressure or constant volume conditions. Constant pressure instruments pass feed gas over one side of the membrane and a sweep gas over the other side of the membrane.

The feed gas is comprised of the gases which are to be separated while the sweep gas is inert and serves the purpose of carrying away the gas that passes through the membrane (i.e. , the separated gas). By carrying away the separated gas, the sweep gas allows for increased efficiency of the separation. Constant volume instruments are set up with a membrane separating a pressurized vessel and an evacuated vessel. The pressurized vessel contains the gases which are being separated. As the gases permeate through the membrane, the pressure in the evacuated vessel will increase. The rate of pressure increase permits a determination of the ability of the membrane to separate the gases.

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Australian Scientists Report New CCS Technology

In a study published recently in Angewandte Chemie, Australian scientists from Monash University and the Commonwealth Scientific and Industrial Research Organisation report the discovery of a photosensitive metal organic framework (MOF) – a class of materials known for its exceptional capacity to store gases. The authors say this has created a powerful and cost-effective new tool to capture and store, or potentially recycle, carbon dioxide. By using sunlight to release the stored carbon, the new material reportedly overcomes the problems of expense and inefficiency associated with current, energy-intensive methods of carbon capture. Current technologies use liquid capture materials that are then heated in a prolonged process to release the carbon dioxide for storage. Read more  Read more