GEOSCAN Search Results: Fastlink

GEOSCAN Menu


TitleA review and assessment of technologies for the geological storage of CO2 as gas hydrate in aquifers
DownloadDownloads
AuthorGunter, B; Macdonald, D; Wagg, B; Chalaturnyk, R; Lakeman, B; Brown, K; Uddin, M
SourceGeological Survey of Canada, Open File 6575, 2011, 65 pages, https://doi.org/10.4095/288700
Year2011
PublisherNatural Resources Canada
Documentopen file
Lang.English
Mediaon-line; digital
File formatpdf
Subjectshydrogeology; fossil fuels; aquifers; bedrock aquifers; groundwater; carbon dioxide; underground gas storage; gas storage; underground storage; hydrocarbons; gas
Illustrationstables; flow charts
Viewing
Location
 
Natural Resources Canada Library - Ottawa (Earth Sciences)
 
ProgramGas Hydrate Production, Gas Hydrates
Released2011 06 07
AbstractGovernments from around the world have expressed an interest in taking action to address the risks of global climate change. One recent approach for preventing large volumes of CO2 from being released into the atmosphere is the capture of CO2 from industrial facilities and storing it in deep geological formations. One CO2 storage application could involve the capture, transport and storage of CO2 as a hydrate in aquifers in locations where CO2 hydrate formation is possible or methane hydrates already exist. This paper outlines the technologies that would be associated with this CO2 storage application.
Gas hydrates or clathrate hydrates are ice-like solids, non-stoichiometric compounds of gas molecules and water. They form when low molecular guest molecules such as CH4 or CO2 come into contact with water under certain thermodynamically favourable conditions (typically, temperature less than 300K and pressure more than 0.6 MPa). Three specific reservoir types have been identified by the Geological Survey of Canada as having the appropriate pressure and temperature conditions to maintain stable CO2 hydrates:
1. sub-sea sediments 2. sub-permafrost aquifers in the far north 3. sub-lake sediments below Lake Superior In some cases, these technologies will be similar to other CO2 storage applications. Perhaps CO2 hydrate formation is most similar to CO2 storage associated with coalbed methane except that in coals, the CO2 is sorbed to the coal as a dense phase. Certain conditions for storing CO2 in hydrate form are quite different from other CO2-storage applications such as CO2 enhanced natural gas recovery or CO2 enhanced oil recovery. Hydrate conditions may require different technologies to be considered in the capture, transport, injection and monitoring of CO2.
Additionally, numerical studies will be important for providing an integrated understanding of the process mechanisms in predicting the potential and economic viability of methane production and CO2 storage in a hydrate geological reservoir. With respect to the capture of CO2 that could ultimately be stored as a hydrate, the feasibility and likelihood of commercial application of CO2 capture technology depends very much on the industrial process from which the waste CO2 stream is produced. There are a number of processing options available for separation of CO2 from produced gas streams containing CO2, including gas separation membranes, chemical absorption, physical absorption and cryogenic systems. All of these have been used commercially. Mackenzie Valley gas could also be handled using commercially available processes if they contain sufficient CO2 for a large scale hydration operation. Final selection of capture technology would depend on process specifics, such as gas stream composition, pressure, flow rate, and operating costs. The location of storage opportunities somewhat limits the potential sources of CO2 and suggests that relatively long CO2 pipelines may be required. CO2 can be pipelined in dense phase at temperatures from –25°C to 0°C, thereby reducing the impact in permafrost areas. As a general rule, transportation costs still are only 5-15% of overall projects costs with capture being the vast majority (80%) of overall costs. The risks associated with the handling and transport of pure CO2 are technically manageable and low, relative to the risks associated with many other industrial gases and chemicals. Properly designed and operated, a high-pressure CO2 pipeline should present minimal health and safety risk. Further, the risks associated with operating a high-pressure CO2 pipeline are significantly less than those associated with produced hydrocarbon streams containing H2S. Operations where CO2 is injected into subsurface aquifers to form stable hydrates in the reservoir face some unique challenges in designing and operating the transportation and well systems. For example, warm gas (above the hydrate stability temperature at the injection pressure) may need to be injected to ensure hydrates do not form near or in the wellbore. As well, shut down scenarios for the CO2 pipeline transportation system must minimize the volume of cold gas that would be injected into the wells at restart to minimize the risk of forming hydrates in the well and reducing injectivity. Wells that penetrate permafrost zones must be insulated to prevent gas cooling and thaw of the permafrost. Injection pressures must be managed to prevent hydraulic fracturing in the reservoir and to minimize formation movements that could impact the well seal integrity. Ultimately, casing and cement corrosion downhole can be minimized with appropriate selection of materials. Reservoir modelling was the prime objective of an accompanying report. Results were promising for CO2 hydrate storage. Future focus should be on: evaluating accompanying ice formation in the lower temperature reservoirs; injection of hot CO2 into 100% water saturated aquifers near 0oC; co-production of methane from existing hydrates and CO2 storage in hydrates; geomechanics of permeability changes during hydrate formation; competing carbonate mineral reactions with CO2 hydrate formation; slurry injection of hydrates; and horizontal well placement.
Monitoring and verification are an integral part of the performance assessment of a geological storage project. As such, the implementation of an appropriate monitoring scheme is the core of a monitored decision framework. The focus of monitoring depends on the phase of monitoring (operational, verification or environmental) and the particular mechanism (i.e. migration, leakage or seepage) being measured. The monitoring systems will be different for each reservoir situation and reservoir type. There are a variety of effective tools and methods for monitoring the injection of CO2 underground that will delineate how the fluid is migrating, and whether or not the sink is leaking. These monitoring techniques combined with analytical and numerical techniques will help to either validate or adjust the predicted migration of the CO2 plume, and the soundness and robustness of the properties input into the models, as well as to take any mitigation activity if the facility underperforms. The cost versus benefit must be weighed in eciding which monitoring techniques to apply.
GEOSCAN ID288700