IMPORTANCE OF COAL SEAM CHARACTERIZATION IN A COAL CO2 SEQUESTRATION PILOT- ILLINOIS BASIN TANQUARY SITE, USA

The potential for sequestering CO2 in the largest bituminous coal reserve in United States (Illinois Basin) is being quantified with a pilot injection project in southeastern Illinois as part of the U.S. Dept of Energy's Regional Sequestration Partnership program. To accomplish the main objectives of this pilot, which are to determine CO2 injection rates and storage capacity, a detailed coal characterization program was developed to improve understanding of the field observations. At the Tanquary injection site, the targeted Springfield Coal is high volatile bituminous B rank (Ro average of 0.62%), 7 ft thick, and occurs at 900 ft depth. The seam was examined in core from one injection and three observation wells spaced approximately 50 to 100 ft apart and oriented relative to cleat directions.

Desorbed coal gas content from one foot core intervals varies from 150 to 210 scf/ton (dmmf) and consists generally of >92% CH4 with lesser amounts of N2 and then CO2. Coal maceral composition averaged 70.2% vitrinite, 3.6% liptinite, 13.9% inertinite and 7.3% mineral matter with considerable variation, particularly in inertinite content. As CO2 adsorption varies with maceral type, relative maceral abundance significantly affects the sequestration potential, being greatest in the vitrinite-rich (bright) coal and decreasing significantly in the inertinite-rich (dull) coals. Coal cleats are well developed with 1 to 2 cm spacing and may be partially filled with calcite and/or kaolinite that decrease coal permeability. CH4, and CO2 adsorption isotherms indicate at least 3 molecules of CO2 can replace each displaced CH4 molecule.

High resolution open-hole logs reveal variation in the potential coal permeability with the shallow resistivity curve in the basal 2 feet showing much higher resistivity than the medium or deep curves, due to increased fresh water drilling fluid invasion into the near well bore compared to the deeper more saline indigenous fluid. Gamma Ray and bulk density vary somewhat, reflecting differences in maceral, ash and pyrite content. Neutron porosity, which is sensitive to hydrogen atoms, shows high variability. Because these coal characteristics will vary across the Basin, it is critical to completely characterize the coal seam at any injection site in order to best predict the potential for CO2 injection.