Abstract Geological sequestration of CO 2 in brine-saturated formations has been proposed as a possible method to reduce emissions of this greenhouse gas to the atmosphere. To optimize the effectiveness of this method, the largest possible volume of CO 2 should be sequestered over geological time. Sequestration over geological time can be thought of as permanent for the purposes of relieving climate-changing increases in atmospheric CO 2 concentration. The least risky way to achieve permanent sequestration is to store the CO 2 as a residual phase within a brine aquifer. Geological conditions that impact the volume of CO 2 stored as a residual phase include petrophysics, burial effects, temperature and pressure gradients, and CO 2 pressure-volume-temperature character. Analyzing and integrating all of these parameters result in an optimal CO 2 sequestration depth for a given geological subprovince. The integrated sequestration optimization model was constructed using petrophysical, geological, and CO 2 characteristics. Sequestering CO 2 as a residual nonwetting phase is one way to ensure its residency in rock over geological time. Thus, residual saturation and porosity were pivotal modeling characteristics. Sediment burial depth affects porosity, temperature, and pressure; thus depth is a key input variable that integrates the other parameters. Finally, CO 2 density as a function of temperature and pressure was accounted for, resulting in a model that combines all the salient properties that affect the amount of CO 2 that can reside within buried rock. A model for predicting residual nonwetting-phase saturation and a sequestration optimization curve (SOC) was developed. Results indicate that a sandstone porosity of 0.23 is optimal for CO 2 sequestration. The SOC for the Frio Formation, upper Texas Gulf Coast, indicates that the largest volume of CO 2 could be trapped as a residual phase at about 3048–3657 m (10,000–12,000 ft). The SOC of depth versus CO 2 residual-phase bulk volume is a concave-down parabolic shape with a broad maximum indicating the optimal sequestration depth. Additionally, greater depth decreases the risk of surface leakage and increases the pressure differential between hydrostatic and lithostatic so that higher injection pressures and, thus, higher injection rates can be obtained.

Abstract The Jordan (San Andres) reservoir comprises ~400 ft (120 m) of upward-shoaling subtidal to peritidal carbonate strata, which is now thoroughly dolomitized and partly cemented by sulfates. Subtidal facies include dominant pellet packstone/ grainstone, with local bryozoans, algae, and coral bioherms and associated skeletal grainstone flanking beds. The lower part of the subtidal section is characterized by stratigraphically distinct zones in which permeability has been enhanced by a postburial carbonate-leaching event. These diagenetically altered (leached) zones crosscut subtidal depositional facies. Peritidal facies are nonporous mudstone and generally non- porous pisolite packstone characterized by abundant sulfate cement. The pisolitic rocks are locally porous and permeable where sulfate cement is either leached or absent from fenestrae. Cumulative production is 68 million stock tank barrels (MMSTB) of 218 MMSTB original oil in place, which is a recovery efficiency of 31%. A total of 47 MMSTB of remaining mobile oil occurs as bypassed oil in the contacted upper part of the reservoir, which has been penetrated by well bores; 12 MMSTB of mobile oil is in the uncontacted lower part, which has not been penetrated by well bores. The most prospective areas for increased production by waterflood profile modification in the contacted part of the reservoir are the southwest corner of the field, where low-permeability, diagenetically unaltered subtidal rocks are incompletely swept, and the eastern central part of the field, where heterogeneous permeability in peritidal rocks has resulted in an incomplete sweep. The most prospective areas for increased production through well-bore deepening into the uncontacted part of the reservoir are the southeast corner of the field, where high-permeability, diagenetically altered subtidal rocks are uncontacted, and the central part of the field, where high-permeability, diagenetically altered subtidal rocks are uncontacted. An understanding of diagenetically controlled reservoir properties can be used to predict the locus of remaining resource and to design recovery strategies.