Wednesday, May 13, 2009

CO2 Sequestration - How Secure Does This Make You Feel?

I think this is frightening - 2 Articles

How safe is CO2 sequestration? How much do the experts really know?
Remember - the largest portion of these experiments are paid for by taxpayers!

Article #1) January 24, 2007 - "Participants were asked to formulate questions and identify research needs to be addressed as EPA prepares to develop a scientifically-sound management strategy for CO2 injection."
(they are listed in the article - several pages of questions) -

Article #2) THREE months later -An announcement saying the well was ready for CO2 sequestration in Shadyside, OH

At that time, there were already MORE "CO2 sequestration Demonstration" projects on the radar for Ohio....... and all over the world...with many more in progress.

"State Regulators Workshop on Geologic Sequestration of CO2
The Environmental Protection Agency (EPA), in coordination with the Department of Energy’s National Energy Technology Laboratory (NETL), and the Ground Water Protection Council (GWPC) held a workshop on geologic sequestration of carbon dioxide (CO2) on
January 24, 2007 in San Antonio, Texas. At the workshop, representatives of state governments, EPA Regions, DOE research laboratories and Regional Partnerships, industry, non-governmental organizations (NGOs), academia, and other interested parties met in small groups to discuss issues associated with CO2 injection for the purposes of geologic sequestration (GS).

Participants were asked to formulate questions and identify research needs to be addressed as EPA prepares to develop a scientifically-sound management strategy for CO2 injection. The participants were organized into groups of 8 to 10 people, with each group having a mix of representatives from EPA regions, states, industry, research institutions, academia, and NGOs, to allow for sharing various points of view. The group discussed the following topics: site characterization; modeling; area of review (AoR); injection well construction; mechanical integrity testing (MIT); measuring, monitoring, and verification (MMV); closure and post-closure care; and liability and financial responsibility."

Click here for the entire article You will WANT TO READ this article.

Then - just 3 months later -

Issued on: April 24, 2007

"Regional Partnership Completes 8,000-foot Well for Critical Carbon Sequestration Assessment

Midwest Regional Carbon Sequestration Partnership Prepares for Test of Geologic Carbon Sequestration in Appalachian Basin

Washington, DC - The Midwest Regional Carbon Sequestration Partnership (MRCSP) has completed an 8,000-foot well at FirstEnergy's R. E. Burger Plant near Shadyside, Ohio, in preparation for a geologic sequestration field test. Sponsored by the Office of Fossil Energy's National Energy Technology Laboratory, the field test will determine the feasibility of storing CO2 in deep saline formations in the Appalachian Basin.

"The carbon sequestration field test in the Appalachian Basin is an important step in turning the promise of carbon sequestration into a reality," said Acting Assistant Secretary for Fossil Energy Tom Shope. "By assessing carbon storage in an area of the country that produces 20 percent of the nation's electricity, the test helps pave the way toward a future in which America's abundant fossil resources can be used to produce energy without contributing to global climate change."

Read the rest of the article here

Skating to the dark side on thin ice

June 29, 2008

When burned, coal produces three times its own weight in carbon dioxide (CO2) -- making it far dirtier than any other energy source, per unit of usable energy. Carbon dioxide is the main human contributor to global warming, so as more people worry about the future of human civilization in a hothouse world, new coal plants are being canceled across the country.

To protect its enormous investment in land, equipment, politicians and environmental groups, the coal industry has bet its future on an untried technology called "carbon capture and storage" (CCS). The idea is to capture the carbon dioxide emitted by burning coal, compress it into a liquid and bury it a mile below ground, hoping it will stay there forever.

The coal industry's fanciful name for this is "clean coal," a.k.a. carbon sequestration. And even though clean coal does not actually exist anywhere on Earth, the industry has sold the idea so effectively that more than 60 percent of Americans say they favor it.

To gain permission to build new coal plants, the coal and electric power industries are now promising the moon: "This new coal plant will be 'capture-ready.' Just let us build this plant now, and we'll add a CCS unit onto the back end as soon as CCS technology has matured and is affordable."

In other words, the industry is saying, "Let us build 'capture-ready' coal plants now, and someday, eventually, maybe, we'll be able to capture the CO2 and bury it in the ground, where we hope it will remain forever."

This is precisely the situation at Duke Energy's 'capture-ready' plant being proposed at Edwardsport in Knox County, upwind of Bloomington.

The 630-megawatt Edwardsport plant will emit an estimated 4,300 tons of CO2 per year (unless and until CCS is tacked onto the plant). Therefore, during its 40-year lifetime, the plant will produce an estimated 172,000 tons, or 344 million pounds, of CO2.

Duke Energy executives insist that the deep earth beneath Edwardsport is ideal for storing hazardous liquid CO2. At least one major environmental group -- the Clean Air Task Force, headquartered in Boston -- agrees with them.

A recent news report in the Herald-Times says, "Clean Air Task Force representative John W. Thompson describes the Duke carbon sequestration initiative as a pioneering effort that could provide a template for other companies and countries to ameliorate global warming by safely storing carbon dioxide..."

When Duke Energy officials met with the editorial board of the Herald-Times, the Clean Air task Force tagged along to provide Duke Energy a patina of green.

Indiana earthquakes so powerful they shake the ground in New Hampshire

Edwardsport lies in Knox County in southwestern Indiana, about 55 miles north of Evansville. Southwestern Indiana lies atop a geologic feature known as the "Wabash Seismic Zone." Because it was only discovered in recent decades, the Wabash Seismic zone is not nearly so well known as the nearby "New Madrid Seismic Zone."

The New Madrid Seismic Zone is famous for the earth-shattering quakes it spawned during 1811 and 1812 -- some quakes registered a magnitude 8 on the Richter scale and were felt in New Hampshire and rang church bells in Washington, D.C., according to the Indiana Geological Survey.

Here's what the Central United States Earthquake Consortium has to say about the Wabash Seismic Zone:

"Recent studies have indicated that the New Madrid Seismic Zone is not the only 'hot spot' for earthquakes in the Central United States. On June 18, 2002, a 5.0 magnitude earthquake struck Evansville, with an epicenter between Mt. Vernon and West Franklin in Posey County, in an area that is part of the Wabash Valley Seismic Zone. ...

"The Wabash Valley Seismic Zone is located in Southeastern Illinois and Southwestern Indiana, and it is capable of producing 'New Madrid' size earthquake events. ..."

Just two months ago, on April 18, a magnitude 5.2 earthquake shook the Wabash zone, with its epicenter only 34 miles from Edwardsport. Since then nearly three dozen earthquakes have occurred in the Wabash zone, 29 of them strong enough for local people to feel.

In other words, the Wabash zone is very active: "A magnitude 1.0 earthquake is probably happening once a week somewhere in the Wabash seismic zone," says Michael Hamburger, an IU professor of geological sciences.

Lubricating the geology

Read the rest of the article here

Interesting Aspects of the CO2 Sequestraion Pilot Project - R.E. Burger Plant -- Ohio

The web site for this article can be found here

You'll want to scroll down and read these.........amazing isn't it?

Carbon Sequestration Regulation and Permitting Moves Forward

Carbon capture and sequestration (CCS) is a critical strategy proposed for combating climate change. It involves the injection of CO2, a greenhouse gas, generated by coal-fired power plants and industrial facilities deep beneath the earth's surface for long term storage.

There are potential significant issues with CCS, including:

  1. 1. Pollutants from the plant mixing with the CO2 that is injected leading to contamination of water supplies;
  2. 2. Potential mobility of CO2 once it is injected; and
  3. 3. Corrositivity of CO2 may result in release of subsurface contaminants into drinking water supplies

The Department of Energy and Coal State's are betting heavily on the success of carbon sequestration. Federal funds are supporting some 25 projects around the country that will investigate the feasibility of CCS.

To address the concerns with CCS, U.S. EPA and the States are beginning to develop regulations for CCS projects. This Summer major developments include release of U.S. EPA's rules and the issuance of an Underground Injection Control (UIC) permit by Ohio EPA for an Ohio test site.

Beginning this month, the Midwest Regional Carbon Sequestration Project (MRCSP) is utilizing FirstEnergy's R.E. Burger Plant as a test site for injection of up to 3,000 tons of CO2. As reported on the MRCSP web page, the period of injection could vary from three to eight weeks, depending on the properties of the injection zones and the time needed for experimental set-up, regulatory oversight and monitoring.

The injection follows Ohio EPA's issuance on September 2, 2008 of a permit to allow the installation and pilot testing of the underground injection well for purposes of carbon sequestration. This is the first permit issued in Ohio that would allow injection of CO2 subsurface for purposes of carbon sequestration. Some interesting aspects of the permit include:

  1. Injection will occur at three different geologic locations- the intervals range from 5,923 feet to 8,274 feet below surface. The intervals are selected to prevent mobility of the injected CO2.
  2. Closure financial responsibility- Total project closeout including closure of the well in accordance with regulatory requirements were estimated at $75,000 to $100,000. This amount only covers sealing of the well. No money is set aside in the event any other issues arise. Some may question whether this is sufficient financial assurance if it was anything other than a test site.
  3. Monitoring of Injected Fluids- On a quarterly basis, the injected material will be analyzed for various contaminants including SO2, NOx, particulate matter, and mercury. The monitoring is an attempt to verify contaminants from the plant are not mixed with the injected CO2.

Issuance of the permit precedes finalization of U.S. EPA proposed rules governing regulation of carbon sequestration projects. U.S. EPA's proposed rules and Ohio EPA's permit rely on similar legal authority on the Safe Drinking Water Act (SWDA). The permit together with the proposed rules give insight into how CCS projects could be regulated in the future. Areas covered by both the permit and U.S. EPA's proposed rule include:

  • Geologic site characterization to ensure that wells are appropriately sited
  • Requirements to construct wells in a manner that prevents fluid movement into unintended zones;
  • Periodic re-evaluation of the area around the injection well to verify that the CO2 is moving as predicted within the subsurface;
  • Testing of the mechanical integrity of the injection well, ground water monitoring, and tracking of the location of the injected CO2 to ensure protection of underground sources of drinking water;
  • Extended post-injection monitoring and site care to track the location of the injected CO2 and monitor subsurface pressures; and
  • Financial responsibility requirements to assure that funds will be available for well plugging, site care, closure, and emergency and remedial response.

While the regulations and permitting of CCS are moving forward, not everyone is embracing CCS. In recent testimony before the U.S. House of Representatives Energy and Commerce Subcommittee on Environment and Hazardous Materials, serious concerns were raised by the American Water Works Association (AWWA) about the potential effect CCS technology may have on the nation's underground sources of drinking water. Strong regulations and successful pilot tests will go a long way to addressing these concerns.

Risk of Arsenic getting into groundwater

The link to the article from which this information was taken is here

Since supercritical CO2 is buoyant at the relevant crustal pressures and temperatures, it will seek the Earth’s surface in most settings. A large CO2 accumulation would exert forces on the reservoir, cap rock, faults, and wells. CO2 must also be injected at pressures above reservoir pressures, creating a pressure transient during and after injection. In addition, dissolved CO2 forms carbonic acid, which can alter rock and well-bore properties and composition. Therefore, despite confidence in the storage mechanisms discussed above, the possibility of leakage from storage sites remains.

These risks were recently highlighted by geochemical analysis and laboratory experiments carried out at a pilot injection in South Liberty, Texas (Hovorka et al. 2006). Kharaka et al. (2006) observed rapid dissolution of some minerals, chiefly carbonate, oxide, and hydroxide minerals. Although this population represented a small fraction of the rock volume (<2%),>.

These studies suggest that while Kharaka et al. (2006) may have discovered a new element of risk, that element does not appear to represent a major concern to CO2 storage. The geomechanical response to CO2 injection may still cause concerns. In a parallel set of studies, Johnson et al. (2005) simulated large pressure excursions from CO2 injection. They concluded that under certain conditions, such excursions lead to fracture dilation, with some seepage of CO2 into overlying units. In the case of most cap rocks, which have both fractures and reactive minerals (e.g. chlorite), this creates a competing rates problem between dilation of fracture and precipitation of reactive minerals in fracture voids. In this system, fracture closure or dilation is sensitive to CO2 diffusion distance and reaction rate. In addition, the pressure transient from injection could lead to fault-slip-induced fluid migration (e.g. Wiprut and Zoback 2002). While it is generally possible to predict the conditions under which this might occur (e.g. Chiaramonte et al. 2006), effective storage will require proper system calibration and injection management.

As mentioned previously, achievement of substantial CO2 emissions reductions through GCS will require hundreds to thousands of large-volume injection facilities distributed around the world. Each existing large project and some small projects (e.g. the Frio Brine Pilot; Hovorka et al. 2006) have provided some demonstration of effectiveness, monitoring technologies, and operational economics. Importantly, each existing large project also has revealed an important aspect of the geology that was not previously known or in some cases incorrectly characterized. For example, at Sleipner, the importance of small flow heterogeneities was not anticipated but was clearly seen (Arts et al. 2004). At Weyburn, CO2 migrated in unexpected ways along secondary fractures (Wilson and Monea 2004). Such features would not have been revealed through a small-scale (<100,000 style="font-weight: bold;">CO2 Dissolution and Precipitation Kinetics

The rate at which CO2 dissolves in brines of varying composition, temperature, pressure, and mixing degree greatly affects the long-term trapping mechanisms (i.e. the formation of carbonic acid, bicarbonate, and new minerals). These issues in turn affect other important concerns, such as the configuration and infrastructure of storage reservoir engineering (e.g. Keith et al. 2005) or the long-term fate of CO2 (Ennis-King and Paterson 2003). Although there has been some work on the controls of dissolution rate (e.g. interfacial effects; Yang et al. 2005) more could be done.
Similarly, knowledge of CO2-brine-mineral dissolution and precipitation kinetics is limited. Recent years have seen many experimental studies on individual minerals or classes of minerals (e.g. Carroll and Knauss 2005 and references therein). Still, much remains to be learned about rock systems, including true multiphase chemistry, mineral–CO2 equations of state, and minerals that may represent only a small volume of the rock but have rapid dissolution kinetics
(e.g. metal oxides or hydroxides).

As a subtopic, most GCS work on mineral reaction kinetics has focused on pure CO2–rock–brine systems. Very little work has been done on gas streams with small concentrations of other gases, in particular SOx, NOx, and H2S. These co-contaminant gases have the potential to dramatically alter the chemical response of a gas–brine–rock system, even if very small amounts of these gases are present (Knauss et al. 2005). Because the capture and separation of trace gases with CO2 may save capital and operating expenses, investigation of reactions in such systems may prove useful in the near future to determine if mixed-gas systems present additional concerns or risks.

The majority of sequestered CO2 will be stored in saline formations at depth. CO2 stored in these formations should have little or no effect on groundwater. However, if CO2 were to reach the surface along some fast pathway, then CO2 might enter fresh groundwater systems. It is highly unlikely that the rate or volume of CO2 would present a problem. However, the results of Kharaka et al. (2006) have raised the possibility that rapid local reactions could release unwanted elements and compounds into groundwater. Again, for most reservoirs this may have no effect. However, some reservoirs have elevated levels of natural arsenic. In such a system, even a small release of CO2 might result in an increase in local arsenic concentrations that could bring a municipal water supply out of compliance with U.S. Environmental Protection Agency regulations. Similarly, widespread deployment of GCS could potentially displace enough water to create saline groundwater intrusions in contiguous formations.


Wells almost certainly present the greatest risk to leakage because they are drilled to bring large volumes of fluid quickly to the Earth’s surface. In addition, they remove the aspects of the rock volume that prevent buoyant migration. Well casings and cements are susceptible to corrosion from carbonic acid. When wells are adequately plugged and completed, they are likely to trap CO2 at depth effectively. However, large numbers of orphaned or abandoned wells may not be adequately plugged, completed, or cemented (Ide et al. 2006), and such wells represent potential leak points for CO2. One analog site is particularly well suited for study. Crystal Geyser, Utah (Shipton et al. 2005), is a well that penetrated a natural CO2 accumulation in 1936, was poorly completed, and has erupted CO2 ever since (FIG. 3). Eruptions are episodic and vary in size. Measurements of individual and sequential eruptions suggest that large events bring tens of tonnes of CO2 to the surface, with an average daily flux of 40–50 tonnes (Gouveia et al. 2005). During the eruptions, atmospheric concentrations of CO2 were not recorded at or above dangerous levels. While this style of eruption does not appear to present a substantial risk (Bogen et al. 2006), more study is needed to understand how representative of well leakage this site may be.

Little is known about the probability of escape from a given well, the likelihood of such a well existing within a potential site, or the risk such a well presents in terms of potential leakage volume or consequence. Current approaches involve statistical characterization of many wells and semiquantitative analysis (Celia et al. 2006), or modeling and simulation of features and processes in well-bore environments (Gerard et al. 2006). Work in understanding the key features of wells (e.g. fracture geometry and character), the chemical response of well components to CO2 systems, and the evolution of natural and engineered interfaces could provide both better estimates of well-bore integrity risk and potential mitigation and remediation strategies (IPCC 2005).