Geologic Storage

About Geologic Sequestration

Geologic sequestration of carbon dioxide (CO₂) involves storage of this greenhouse gas in underground formations, after it has been captured from power plants or other large industrial facilities. It is an idea that is being pursued around the world in view of its potential to mitigate the effect of CO₂ emissions. As part of a broader portfolio of technologies, geologic sequestration appears to be capable of playing an important role in stabilizing CO₂ concentrations in the atmosphere.

CO₂ can be separated and captured as a byproduct of fossil fuel, used for energy generation and numerous industrial processes. Currently a variety of technologies are in use or under development for separation and capture. For example, Integrated Gasification Combined Cycle (IGCC) technology converts fossil fuel, including coal, oil, natural gas, and biomass, into hydrogen gas and other components, including CO₂. This advanced technology facilitates CO₂ capture by creating a relatively pure and concentrated CO₂ stream. In addition, research is underway to develop technologies to capture CO₂ directly from the flue gases from combustion of coal, natural gas, and other fossil fuels. Once captured, CO₂ can possibly be compressed; transported via pipeline, similar to the way natural gas currently is transported; and, injected underground into a suitable storage area. A key focus of ongoing studies outside the MRCSP is reducing the high cost of separation, capture and transport.

Sequestration in geologic formations builds on a strong industry experience base. The primary types of geologic reservoirs for storing CO₂ underground under study are deep saline formations, depleted oil and gas reservoirs, and unmineable coal seams. Many of these reservoirs have naturally stored crude oil, natural gas, brine and CO₂ over millions of years, and thus we know that they have at least the theoretical potential to store CO₂ from anthropogenic (man-made) sources. Many power plants and other large sources of CO₂ are located near geologic formations that are amenable to CO₂ storage. This proximity should reduce costs. Further, in many cases, injection of CO₂ into a geologic formation can enhance the recovery of hydrocarbons, providing value-added byproducts that can offset the cost of CO₂ capture and sequestration.
The U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) is funding extensive research to understand the behavior of CO₂ when stored in geologic formations. For example, studies are being done to determine the extent to which CO₂ moves within the deep subsurface environment and the physical processes and chemical reactions within specific formation types that lead scientists to predict that once injected, CO₂ will remain in these formations permanently.
  • Near-term research efforts will focus on field testing of a variety of geologic storage options in order to ensure that geologic sequestration provides:  1) safe and permanent containment of CO₂; 2) low environmental impact; 3) low cost; 4) conformity with national and international laws and regulations; and 5) public acceptability
  • An important area of study for all types of underground storage is to develop measuring, monitoring and verification (MMV) protocols. Needed protocols include the capability to 1) measure the amount of CO₂ stored at a specific sequestration site; 2) monitor the site for leaks or other storage integrity issues over time; and 3) ensure the stored CO₂ poses no threat to public health or the environment. In addition, each type of geologic reservoir system has its own unique characteristics as they relate to storing CO₂ and a resulting set of research priorities and opportunities.
Deep Saline Reservoirs: Deep saline reservoirs (or brine formations) are saltwater formations located many thousands of feet below the earth's surface. These reservoirs have two important benefits as CO₂ storage options. First, the estimated carbon storage capacity of saline formations in the U.S. is very large, making them a viable long-term solution. And second, many existing large CO₂ point sources are within easy access of a saline formation injection point. As with all of these geologic formations, understanding how CO₂ moves within the formation and ensuring it stays there are key aspects of sequestration research.

NETL has initiated a number of field tests to study the behavior of CO₂ after it is injected into a formation. NETL also seeks to characterize potential sites to ensure the suitability of their geology. Factors to confirm include:
  • The impermeability of the rock (cap rock) above the proposed storage area to prevent CO₂ from gradually moving upwards in the formation. For example, the presence of a thick shale without interconnected cracks would indicate an effective cap (shales have a texture that inhibits fluids or gases from moving through them) 
  • The storage capacity of the rock formation, i.e., whether it can hold enough CO₂ to be worth the cost of injection
  • The distribution of the CO₂ in the reservoir and the chemical reactions that occur between the CO₂ and the reservoir rock and fluids
  •  A lack of faults in the area of injection operation that would avoid migration of fluids.
Oil and Gas Reservoirs:  The U.S. is a world leader in enhanced oil recovery technology (EOR), using about 32 million tons of CO₂ per year for this purpose. In EOR, a combination of CO₂ and water is pumped into depleted oil wells to re-pressurize wells and "push" additional oil toward production equipment. The synergy of EOR in depleted oil and gas reservoirs and CCS are referred to as Carbon Capture, Utilization, and Storage, or CCUS. Incremental increases in domestic oil production through CO₂ EOR would offset an equivalent quantity of imported oil that is produced by primary production which does not involve CO₂ injection or storage. Studies show that a barrel of oil produced using CO₂ EOR is 70% “carbon-free”, after accounting for the difference between carbon content in the incremental oil produced and the volume of CO₂ stored in the field. Further, depleted oil and gas fields are favorable storage containers because of already available geologic data sets; the storage container is already proven to prevent vertical migration; and the recovery of oil stranded deep underground opens up additional storage space.  

Unmineable Coal Beds: Coal beds in the subsurface typically contain large volumes of methane-rich natural gas (called coal bed methane). A high percentage of this gas is adsorbed naturally on to the surface of the coal. Currently, methods for recovering coal-bed methane involve depressurizing the reservoir by pumping water out of the coal, thus permitting those methane molecules adsorbed on the surface of the coal to be released as free gas. An alternative approach for methane recovery is to inject CO₂ into the coal bed. Experiments indicate that coal beds have an affinity to absorb approximately twice as many CO₂ molecules as compared to methane. Thus, the potential exists to displace and recover Thus, the potential exists to displace and recover coal bed methane efficiently. CO₂ recovery of coal bed methane has been demonstrated in limited field tests; however, additional research is needed to understand and optimize the process.

Similar to the by-product value gained from enhanced oil recovery, the recovered methane provides a value-added revenue stream to the carbon sequestration process, creating a lower net-cost option. The DOE Office of Fossil Energy estimates that 90 percent of coal reserves in the U.S. are unmineable due to inadequate coal thickness, extreme depth or a lack of internal continuity of the coal bed. A substantial portion of these unmineable resources may be amenable to methane recovery from CO₂ injection. Many fossil-fired electricity-generating stations (potential candidate sources of CO₂ for geologic sequestration) are located near to or in regions with substantial unmineable coal resources, reducing the extent of pipeline transportation of CO₂ required.

In the past few years, DOE has funded field experiments to thoroughly evaluate CO₂ injection into coal beds. Most notable of these are the Coal-Seq project in the San Juan Basin in New Mexico; and a seven-year project, including a five-year monitoring program, being conducted by CONSOL Energy in the northern panhandle of West Virginia.
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