From Bureau of Economic Geology, The
University of Texas at Austin (www.beg.utexas.edu).
For more information, please contact the author.
Bureau Seminar, March 19, 2010
Application of Gas Geochemistry in Shale Gas Reservoir Geochemical Characterization and CO2/Brine Interaction of CO2 Sequestration in Aquifer
Link to streaming video: available 03.19.2010 at 8:25am
Dr. Tongwei Zhang
Research Associate, Bureau of Economic Geology
Gas chemical and isotopic compositions are useful geochemical indicators to identify gas origins. Gas geochemical features are distinguishable from a variety of geochemical processes, i.e. biodegradation, gas mixing and gas migration, organic-inorganic interaction. Gas geochemistry can provide a unique solution to quantitatively estimate the contributions from each above process. In this study, two geochemical case studies of developing quantitative models for shale gas reservoir geochemical characterization and CO2-bine interaction of CO2 sequestration in aquifer are presented.
Given the importance of shale gas as a source of natural gas and resultant economic interest in gas shales, little is understood about mechanisms of shale-gas storage and shale-gas transport. Our results showed that the total amount of methane adsorbed is directly proportional to the total organic carbon content in shales, indicating that sorption on organic matter plays a critical role in shale-gas storage. Quantitative model predictions based on the Langmuir equation parameters can then be applied to specific organic matter properties. In particular, the value of the Langmuir constant increases with kerogen type in the following sequence: Type I < Type II < Type III. The Langmuir constant is related to the affinity of a gas for a surface (i.e., larger values indicate strong bonding) and the observed trend is likely a product of the increasing aromaticity of the kerogen. These findings have important implications for shale-gas resource assessment and recovery technologies. In order to investigate gas chemistry in shale gas reservoirs, we developed a technique to release gas in rock crushing, which might fill the gap by using existing core for shale gas resource assessment. Preliminary results show optimistic application to determine gas thermal maturity with gas chemistry from rock crushing.
Sampling gases and fluids during deep CO2 injection is challenging, but yields important information on deep subsurface processes. During an engineered CO2 injection at Cranfield, MS, 186 gas samples from 2 observation wells (~3000m depth) were continuously collected over 30 days using a pressure-loop U-Tube sampler and analyzed by gas chromatography. A gas mixing model considering hydrocarbon-rich brines in the reservoir and CO2-rich injectate gas as two end members was used to characterize the origin of the sampled gas during the observation period. Measured concentrations of CO2 and CH4 deviate only slightly from modeled values compared to deviations for C2 and C3. Measured CO2 is slightly lower than modeled values indicating depletion, while CH4 concentrations are slightly higher indicating enrichment. Both C2 and C3 are enriched in the gas phase during CO2 transport over 60m. The magnitude of enrichment for hydrocarbons increases from C1 to C4. These data offer insights into the complex high pressure fluid-gas interactions in this reservoir.
Author would like to thank Jackson School of Geosciences provides Start-up fund to setup gas geochemistry laboratory in Bureau since 2008. The lab has various capabilities to support our research projects.