GEOLOGIC AND HYDROCHEMICAL EVALUATION OF THE SUITABILITY OF THE NAVAJO SANDSTONE FOR CO2 SEQUESTRATION IN CENTRAL UTAH

Growing concern over possible global climate change has spurred research toward finding ways to reduce greenhouse gas emissions. One of the best options volumetrically is to collect CO2 from point sources and inject it into deep confined aquifers. This study has examined the deep saline aquifers underling the Drunkards Wash, Helper and Buzzard Bench gas fields, located in central Utah, to determine if this is a suitable location for the sequestration of CO2 gas. Currently salt water (as part of the production of coal bed methane) is being injected into the Navajo Sandstone at depths ranging between 4,558 ft to 8,218 ft.

Water samples have been analyzed for the stable isotope ratios of deuterium/hydrogen (D/H), oxygen-18/oxygen-16 (18O/16O) and carbon-13/carbon-12 (13C/12C). Samples were also analyzed for major ions and trace metals. Injected salt water yields high ratios (isotopically heavy) of 13C/12C because the source is likely calcite. The carbon source for the fresh water wells most likely is atmospheric and/or soil CO2 gas and is isotopically light.

Three subsurface, north-south trending faults have been identified in the study area from structural cross sections using 479 digital well logs from the Drunkards Wash gas field. One fault has been identified in the north; the other two are in the central part of the gas field near the eastern and western flanks. An anticline has also been located on the southern boundary of the gas field. By calculating the clay smear potential (CSP) ratios in these faulted areas, using the square of the net shale thickness divided by the fault throw, we should be able to determine if these faults are sealing or non-sealing. A low CSP value means there is low probability for the presence of a continuous clay smear along the throw of the fault. Values of 5 to 15 are reported as non-sealing and more than 30 as sealing. A fault may be considered as sealing or as trapping fluids if significant portions of a fault have high to medium CSP values.

The amount of fracturing in the rocks can be qualitatively estimated by comparing gas production in areas where faults have been identified versus areas where no faults exist. Areas near faults may reveal greater gas production than areas that lack faults, as higher gas production has been linked to greater fracture densities as a first order approximation.