CO2 Storage Well Completed in Saskatchewan

The Saskatchewan-based Petroleum Technology Research Centre has announced the completion of a well to be used for testing the deep saline storage of carbon dioxide. At a total depth of 3,396 meters (11,141 feet), the well is the deepest in the province and is part of the Aquistore project, a partnership between the Petroleum Technology Research Centre and the SaskPower Boundary Dam Power Station. SaskPower, the electrical utility for Saskatchewan, runs three coal-fired plants in the province. 

The well was drilled near the city of Estevan in the Deadwood formation, the deepest sedimentary unit in the Williston Basin. It has produced a complete set of logs, core samples and other data that project officials say will be useful not only for CO2 storage, but also for oil companies in the area who have interests in hydrocarbon bearing formations. The Deadwood formation is made up of alternating porous rocks such as limestones and sandstones, and non-porous rocks like shales, anhydrite and salt.

A second observation well will be drilled beginning in October and is expected to be of a comparable depth. Both wells are part of a four year research and monitoring project to demonstrate that storing carbon dioxide deep underground in a brine and sandstone water formation  is a safe, workable solution to reduce greenhouse gases. Saskatchewan has previous carbon storage experience to draw upon. Cenovus Energy (formerly EnCana) has been injecting CO2 into the Weyburn Oil Field since 2000. In addition, Shell Oil piloted CO2 injection into Saskatchewan's Midale Field in the 1980's, which Apache Canada continued in 2005.

(A video that overviews the Weyburn Oil Field application, which uses CO2 from the Great Plains Synfuels Plant near Beulah, is available here.)

Sources: Aquistore, Petroleum Technology Research Centre

New Carbon Capture Bill Introduced

A bill introduced in the U.S. Senate last week would modify the existing carbon capture and storage tax incentive, which provides a credit of $10 per ton of industrial carbon dioxide used in enhanced oil recovery projects and $20 per ton for carbon dioxide placed directly in secure geological storage. The goal of the bill, which was co-authored by Senator Kent Conrad (D-ND), Senator Mike Enzi (R-WY) and Senator Jay Rockefeller (D-WV), is to make the tax credit easier to access for CO2 emitters.

Senator Conrad said this bill reflects the recommendations of the National Enhanced Oil Recovery Initiative (NEORI) for spurring new enhanced oil recovery projects. The NEORI is a working group of almost 30 energy industry members, state regulators, and environmental group members and was co-founded by the Great Plains Institute and the Center for Climate and Energy Solutions.

The Department of Energy estimates that standard oil production techniques leave as much as 80 percent of the original oil in place. Employing carbon dioxide in enhanced oil recovery could lead to a potential 67 billion barrels of economically recoverable oil — an increase of 45 billion barrels from the 22 billion barrels of current U.S. proven oil reserves, according to the National Energy Technology Lab. Read more

British Introduce New Carbon Capture Technology

A new Senate bill introduced last week aims to provide incentives for carbon capture though improved access to tax credits, but it may be a bit premature. The process has not yet been proven on a commercial scale, and some scientists think the ammonia-based materials currently used in typical carbon capture technology actually may contribute to toxic emissions during the process of trying to reduce them.

Current capture processes also require large amounts of heat to separate the carbon so that it can be transported and stored. Power plant officials complain that the capture process is "parasitic"--that is, it significantly reduces the efficiency of the plant by diverting heat to the carbon separation process.

Recent innovations, however, may improve the efficiency and reduce the cost of carbon capture. For example, the Department of Energy last month announced preliminary results of its tests with a new carbon sorbent called BrightBlack, which demonstrated efficiency rates as high as 95% and yielded carbon with purity rates between 95 and 100 percent.

In the BrightBlack process, CO2 is absorbed in a bed of proprietary sorbent pellets and desorbed in a separate reactor that regenerates the sorbent and cycles it back to the absorber at  low thermal temperatures. Through 7,000 absorption-regeneration cycles, and a total of 130 hours of operation, the sorbent showed little-to-no mechanical or chemical degradation. The DOE plans to use the data from the initial pilot project to run scaled-up trials of the process, with the eventual goal of testing it in a pulverized coal boiler.

Meanwhile, British scientists this week announced a new low-cost sorbent called NOTT-300 (from Nottingham University where some of the research occurred) made from aluminium nitrate salt, cheap organic materials and water. In additon to being non-toxic, the material enables captured CO2 to be released using virtually no heat.

The NOTT-300 technology uses two filters. When one filter becomes saturated with carbon, it is removed and the carbon is released through a pressure reduction process while the exhaust gases are diverted to the second filter. The regenerated filter is then reconnected to be used when the second filter becomes saturated, a process the Nottingham scientists say can occur repeatedly and at normal temperatures.

The capture rate during the trial was nearly 100%  The researchers say the rate could be lower in an actual power plant application but should still approach 90%. They also think NOTT-300 could be used in gas separation processes since other gases such as hydrogen, methane, oxygen and nitrogen cannot interact with the material in the same way and therefore cannot be adsorbed.

It is important to point out that these new technologies, while showing great promise, are still only laboratory experiments. It's unknown whether they will work in commercial power plant applications, which are likely many months from being tested.

Sources...

• The U.S. Department of Energy, "Novel Sorbent Achieves 90 Percent Carbon Capture in DOE-Sponsored Test", August 21, 2012
• Financial Post, "Boost for carbon capture from new non-toxic absorber", September 24, 2012
•TCE Today, "New NOTT-300 MOF offers CCS Potential", September 25, 2012

U.S. DOE Begins COE Injection in Alamaba

Washington, D.C. — Carbon dioxide (CO2) injection has begun at the world’s first fully integrated coal power and geologic storage project in southwest Alabama, with the goals of assessing integration of the technologies involved and laying the foundation for future use of CO2 for enhanced oil recovery (EOR).

The "Anthropogenic Test"—conducted by the Southeast Regional Carbon Sequestration Partnership (SECARB), one of seven partnerships in DOE’s Regional Carbon Sequestration Partnerships program—uses CO2 from a newly constructed post-combustion CO2-capture facility at Alabama Power’s 2,657-megawatt Barry Electric Generating Plant (Plant Barry). It will help demonstrate the feasibility of carbon capture, utilization and storage (CCUS), considered by most energy experts as an important option for meeting the challenge of helping to reduce atmospheric CO2 emissions linked to potential climate change.
In a unique process developed by Mitsubishi Heavy Industries, a small amount of flue gas from Plant Barry—equivalent to the amount produced when generating 25 megawatts of electricity—is being diverted from the plant and captured using Mitsubishi’s advanced amine process to produce a nearly pure stream of CO2.

Once captured, the CO2 is transported approximately 12 miles west to the southern flank of a geologic structure called the Citronelle Dome, within the Paluxy saline formation. A pipeline was constructed for this purpose in 2011. The Paluxy is an ideal site for injection because it is more than 9,000 feet underground and is overlain by multiple geologic confining units that serve as barriers to prevent CO2 from escaping.

Carbon dioxide injection will take place over 2 years at a rate of up to 550 metric tons of CO2 per day. Multiple monitoring technologies will be deployed to track the CO2 plume, measure the pressure front, evaluate CO2 trapping mechanisms, and ensure that the CO2 remains in the formation. In 2017, following 3 years of post-injection monitoring, the site will be closed. At that time, the wells will either be plugged and abandoned according to state regulations, or re-permitted for CO2-enhanced oil recovery (CO2-EOR) and CO2 storage operations. If re-permitted, CO2 that would otherwise be emitted to the atmosphere would be used to recover stranded oil while also being sequestered in a geologic formation.

The U.S. Department of Energy’s Office of Fossil Energy established the Regional Carbon Sequestration Partnerships program in 2003 to determine the best geologic and terrestrial storage approaches for each partnership’s specific region and to demonstrate technologies to safely and permanently store CO2. While focusing on regional CCUS opportunities, the seven partnerships collectively form an effective and robust nationwide initiative. Each partnership has developed a regional carbon management plan to identify the most suitable storage strategies and technologies, aid in regulatory development, and propose appropriate infrastructure for CCUS commercialization within its region. FE’s National Energy Technology Laboratory (NETL) manages the partnerships program.

SECARB estimates that 31 percent of the nation’s CO2 stationary source emissions come from within its region, which comprises all or part of 13 southeastern states: Alabama, Arkansas, Florida, Georgia, Kentucky, Louisiana, Mississippi, North Carolina, South Carolina, Tennessee, Texas, Virginia, and West Virginia. The region’s deep saline and oil and gas formations offer safe and permanent storage capacity for these emissions. SECARB, along with the other Regional Carbon Sequestration Partnerships, continues to develop best practices to support the wide-scale transfer and advancement of information and technology derived from its projects.

SECARB’s Anthropogenic Test is led by the Southern States Energy Board in partnership with the Electric Power Research Institute, Southern Company, Alabama Power Company, Denbury Resources, Inc., Advanced Resources International, Inc., and other experts.