Carbon Storage
Geologic Storage Focus Area
Geologiccarbon dioxide (CO2) storage involves the injection of supercritical CO2 into deep geologic formations (injection zones) overlain by competent sealing formations and geologic traps that will prevent the CO2 from escaping. Current research and field studies are focused on developing better understanding 11 major types of geologic storage reservoir classes, each having their own unique opportunities and challenges. Understanding these different storage classes provides insight into how the systems influence fluids flow within these systems today, and how CO2 in geologic storage would be anticipated to flow in the future. The different storage formation classes include: deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef. Basaltic interflow zones are also being considered as potential reservoirs. These storage reservoirs contain fluids that may include natural gas, oil, or saline water; any of which may impact CO2 storage differently. The following summarizes the potential for storage and the challenges related to CO2 storage capability for fluids that may be present in more conventional clastic and carbonate reservoirs (saline water, and oil and gas), as well as unconventional reservoirs (unmineable coal seams, organic-rich shales, and basalts):
- Saline Water
Potential storage reservoirs may contain layers of porous rock saturated with brine. Brine, or saline water, is present reservoirs in most sedimentary basins worldwide. As a result, formations containing saline water have the highest storage potential resource capacity of all geologic media. However, less is typically known about formations baring only saline due to the lack of sufficient subsurface data. Saline water can contain minerals that could potentially react with the injected CO 2 to form solid carbonates. The reactions can increase permanence but could decrease the porosity in the immediate vicinity of an injection well. Researchers seek injection techniques that promote advantageous mineralization reactions. Collapse Text
- Natural Gas and Oil
Oil and natural gas can be present in reservoirs containing layer of permeable rock with a layer of low-permeability rock above, such that the low-permeability layer forms a stratigraphic trap that holds the oil and gas in place. The geologic conditions that trap oil and gas are also the conditions that are conducive to CO 2 sequestration. As a value-added benefit, when CO 2 is injected into an oil-bearing formation, it can produce additional oil (10-15 percent). This process, enhanced oil recovery (EOR), begins with the injection of CO 2 into an oil reservoir. A small amount of injected CO 2 dissolves in the oil, increasing the bulk volume and decreasing the viscosity, thereby facilitating flow to the wellbore. However, commercial practitioners operate their injections with the goal of minimizing the amount of CO 2 left in the ground so that the CO 2 can be used for another well. NETL's work in this area is focused on EOR and enhanced gas recovery (EGR) injection practices that maximize the amount of CO 2 sequestered. Collapse Text
- Unmineable Coal Seams
Unmineable coal seams are too deep or too thin to be economically mined. All coals have varying amounts of methane (CH 4) adsorbed onto pore surfaces, and wells can be drilled into unmineable coal seams to recover coal bed methane (CBM). Initial CMB recovery methods leave a considerable amount of CH4 in the formation, but this can be increased by injecting CO 2. CO 2 is adsorbed onto the surface of the coal and the methane is desorbed (enhanced coal bed methane [ECBM] recovery). Coal swelling is a potential barrier to CO 2 ECBM due to a sharp drop in permeability, which not only restricts the flow of CO 2 into the formation but impedes the recovery of CBM. Angled drilling techniques and fracturing are possible means of overcoming the negative effects of swelling. Collapse Text
- Organic-Rich Shale Basins
Shale, the most common sedimentary rock, is characterized by thin horizontal layers of rock with low permeability in the vertical direction. Many shales contain 1-2 percent organic material in the form of hydrocarbons, which provide an adsorption substrate for CO 2 storage similar to CO 2 storage in coal seams. Research is focused on achieving economically viable CO 2 injection rates, given the low permeability of shale. Collapse Text
- Basalt
Basalt formations are geologic formations of solidified lava. Basalt formations have the unique chemical makeup that could potentially convert all of the injected CO 2 to a solid mineral form, thereby isolating it from the atmosphere permanently. Research is focused on enhancing and utilizing the mineralization reactions and increasing CO 2 flow within a basalt formation. Collapse Text
Geologic storage of oil, gas, and CO2 in the deep subsurface has been naturally occurring for millions of years. For more than 40 years the oil industry has injected CO2 in depleted oil reservoirs for the recovery of additional product through enhanced oil recovery (EOR). Natural analogs to CO2 storage exist throughout the United States, where CO2 has been naturally trapped in confined geologic layers and structures deep below the surface of the Earth. Lessons learned from natural systems, EOR operations, gas storage, and sponsored CO2 storage projects are all important for developing storage technologies for a future CCS industry.
Geologic Storage Research Goals
NETL's Core R&D research in the Geologic Storage Focus Area is based on developing the ability to characterize a geologic formation before CO2-injection to be able to predict the CO2 storage resource and developing CO2 injection techniques that achieve broad dispersion of CO2 throughout the formation, overcome low diffusion rates, and avoid fracturing the cap rock. These areas of site characterization and injection techniques are interrelated because improved formation characterization will help determine the best injection procedure. As part of NETL's effort to adequately understand and characterize these potential storage formations, they are supporting the development of tools and protocols to:
- Improve the ability to predict storage capacity in closed and open geologic systems to within ± 30 percent.
- Assess and minimize the impacts of CO2 and co-contaminants on geophysical processes.
- Develop remediation technologies that will prevent or reduce possible releases through existing wellbores and natural pathways.
The following figure illustrates the geologic storage concept and the different areas of research being pursued within the Geologic Storage R&D effort.
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| Diagram of Geologic Storage Concept Highlighting Current Research Areas (click to enlarge) |
Geologic Science and Technologies Research
A future geologic CO2 storage industry will need to augment existing technologies with novel technologies to ensure permanent storage of CO2. The Carbon Storage Program looks to support research that will better our scientific understanding of the following areas:
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- Properly constructed wellbores are necessary to ensure safe and reliable injection operations and long-term containment. Wellbores must be made of materials that are resistant to the materials being injected and any changes in the fluid chemistry of the injection formations. They must also be resistant to mechanical stresses on the storage formation and seals and have good cement bonds within the geologic formation to ensure containment. Drilling and stimulation technologies are also an important area of consideration. These technologies may be advantageous for CO2 storage projects by enhancing capacity and injectivity.
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- Improve construction materials for products (such as casing, linings, and cements) to increase resistance to degradation caused by CO2, other co-contaminants, and the fluids in the reservoir which may react with the CO2.
- Adapt tools that allow improved directional drilling and stimulation methods to increase the use of marginal storage reservoirs.
- Improve protocols and technologies that increase injectivity, improve storage efficiency, and increase capacity.
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- Permanent CO2 storage relies on the presence of a competent geologic seal which will retain the CO2 for millennia. Penetrations, such as wellbores and natural faults and fractures, offer potential release pathways for CO2 to migrate to the surface or underground sources of drinking water (USDW), negating the benefits of removing the CO2 from the atmosphere. Mitigation technologies are necessary to ensure that any possible releases through these pathways can be addressed. Some existing mitigation technologies and protocols from the oil and gas industry can be used to permanently seal wells that are poorly constructed or have degraded after years of operation. These existing technologies will need to be adopted and new technologies will need to be developed to mitigate potential CO2 releases.
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- Develop techniques and technologies to mitigate poor cement bonds within the annular space between well casings and surrounding rock by squeezing fluids (i.e., cement) to improve the seal.
- Develop micro drilling and injection technologies to both access potential CO2 release pathways and inject flow-reducing fluids to mitigate any release.
- Develop biological or chemical additives that could seal release pathways at the caprock or wellbore while having no impact on CO2 injectivity and capacity efficiency in the storage formation.
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- Carbon dioxide injected into the subsurface will need to move through the storage formation between the grains of sand in clastic formations, vugs or fractures in carbonate reservoirs, and cleats in coalbeds. The CO2 typically will take the path of least resistance, possibly bypassing areas capable of storage. This would result in pore space not being fully utilized (known as poor sweep efficiency), reducing the total storage capacity of the formation. Additionally, CO2 will displace brine during injection operations. In open systems, the brine will typically move laterally as it is displaced by injected CO2. However, in closed systems, brine may have not place to migrate and may need to be removed to prevent pressure from impeding the injection operations. In either case, brine management techniques will need to be understood to avoid an adverse impact to CCS operations.
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- Support research to better understand fluid flow in different geologic strata to help improve operation and design requirements as well as injectivity and sweep efficiency.
- Understand the impacts of injection on both closed and open systems at project and basin scales.
- Support the development of technologies and protocols for the management of brine extracted from CCS operations.
- Determine the optimal placement of injection and monitoring wells in each type of depositional environment.
- Understand the effects of multiple injection wells, pressure, and groundwater flow on CO2 injection and storage.
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- Carbon dioxide will react with rock interfaces, minerals, and brines in the storage formation. Chemical processes relevant to subsurface CO2 storage include aqueous speciation, dissolution/precipitation, microbial-mediated redox reactions, ion-exchange between solutions and minerals, and surface chemical reactions occurring at phase interfaces. All of these reactions will have impacts on the physical processes happening in the storage formation, the caprock, and on a smaller scale through leakage pathways.
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- Understand the impacts of CO2 on mineralization rates in different formation types to improve CCS operations and storage integrity.
- Understand potential impacts of co-contaminants on precipitation of minerals and their effect on the storage formation.
- Understand the impacts of geochemical reactions with brine, cements, casing materials, and materials that seal faults and fractures.
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- Injection of CO2 will occur at pressures above the natural reservoir pressure. In most projects the injection pressure will be below the fracture pressure for the caprock, significantly reducing the risk of release and associated geomechanical effects. Some injection operations may also take place in hydraulic fractured (stimulated) wells that were used for hydrocarbon recovery. All of these situations lead to questions about the impacts of CO2 injection on the reservoir and the confining formations.
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- Use microseismicity to understand reservoir characteristics and fluid flow.
- Examine impacts on caprock, faults, fractures, and existing wellbore materials.
- Understand the general pressure distribution on different reservoirs based on their depositional environment.
- Determine impacts of injection on existing hydraulically featured geology.
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The program is also looking to support research to develop technologies that can improve containment, improve injection operations, increase reservoir storage efficiency, and mitigate releases. The following table summarizes NETL's active projects that are currently addressing the critical geologic storage barriers.
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