Bibliography - B. R. Ellis

1. Ellis, B. R., Grant S. Bromhal, Dustin L. McIntyre, and Catherine A. Peters, 2011: Changes in caprock integrity due to vertical migration of CO₂-enriched brine. Energy Procedia, 4, doi:10.1016/j.egypro.2011.02.514 5327-5334
   [ Abstract ]

   In geologic carbon sequestration, caprock fractures may act as leakage pathways, threatening the long term sealing ability of the formation. A flow-through experiment was performed to investigate fracture evolution of a fractured carbonate caprock during simulated leakage of CO₂-acidified brine. The initial brine composition represented that of a CO₂-saturated brine having previously reacted with the injection formation minerals resulting in a starting pH of 4.9. Experimental temperature and pressure conditions were 40°C and 10 MPa, corresponding to injection at a depth of 1 km. A combination of X-ray computed tomography and scanning electron microscopy was used to observe fracture evolution and investigate the mineralogical changes that occurred along the fracture wall. After one week of brine flow, the cross-sectional fracture area increased by an average of 2.7 times that of the initial fracture. The fracture surface was not eroded uniformly, with the largest areas of aperture growth corresponding to direct contact between the acidified brine and calcite. This preferential dissolution of calcite led to a large increase in fracture surface roughness and in some instances, created a silicate mineral-rich microporous coating along the fracture wall. Results from this study suggest that the clay content of low permeability carbonate formations may be an important factor in controlling their long term integrity while in contact with acidified brine and should be considered when selecting appropriate injection sites for geologic CO₂ sequestration.

2. Ellis, B. R., Lauren E. Crandell, and Catherine A. Peters, 2010: Limitations for brine acidification due to SO₂ co-injection in geologic carbon sequestration. International Journal of Greenhouse Gas Control, Elsevier, (4), doi:10.1016/j.ijggc.2009.11.006 575-582
   [ Abstract ]

   Co-injection of sulfur dioxide during geologic carbon sequestration can cause enhanced brine acidification. The magnitude and timescale of this acidification will depend, in part, on the reactions that control acid production and on the extent and rate of SO₂ dissolution from the injected CO₂ phase. Here, brine pH changes were predicted for three possible SO₂ reactions: hydrolysis, oxidation, or disproportionation. Also, three different model scenarios were considered, including models that account for diffusion-limited release of SO₂ from the CO₂ phase. In order to predict the most extreme acidification potential, mineral buffering reactions were not modeled. Predictions were compared to the case of CO₂ alone which would cause a brine pH of 4.6 under typical pressure, temperature, and alkalinity conditions in an injection formation. In the unrealisticmodel scenario of SO₂ phase equilibrium between the CO₂ and brine phases, co-injection of 1% SO₂ is predicted to lead to a pH close to 1 with SO₂ oxidation or disproportionation, and close to 2 with SO₂ hydrolysis. For a scenario in which SO₂ dissolution is diffusion-limited and SO₂ is uniformly distributed in a slowly advecting brine phase, SO₂ oxidation would lead to pH values near 2.5 but not until almost 400 years after injection. In this scenario, SO₂ hydrolysis would lead to pH values only slightly less than those due to CO₂ alone. When SO₂ transport is limited by diffusion in both phases, enhanced brine acidification occurs in a zone extending only 5 m proximal to the CO₂ plume, and the effect is even less if the only possible reaction is SO₂ hydrolysis. In conclusion, the extent to which co-injected SO₂ can impact brine acidity is limited by diffusion-limited dissolution from the CO₂ phase, and may also be limited by the availability of oxidants to produce sulfuric acid.

3. Crandell, Lauren E., B. R. Ellis, and Catherine A. Peters, December 2009: Dissolution Potential of SO₂ Co-Injected with CO₂ in Geologic Sequestration. Environmental Science and Technology, University of Iowa, Iowa City, doi:10.1021/es902612m
   [ Abstract ]

   Sulfur dioxide is a possible co-injectant with carbon dioxide in the context of geologic sequestration. Because of the potential of SO₂ to acidify formation brines, the extent of SO₂ dissolution from the CO₂ phase will determine the viability of co-injection. Pressure-, temperature-, and salinity-adjusted values of the SO₂ Henry's Law constant and fugacity coefficient were determined. They are predicted to decrease with depth, such that the solubility of SO₂ is a factor of 0.04 smaller than would be predicted without these adjustments. To explore the potential effects of transport limitations, a nonsteady-state model of SO₂ diffusion through a stationary cone-shaped plume of supercritical CO₂ was developed. This model represents an end-member scenario of diffusion-controlled dissolution of SO₂ , to contrast with models of complete phase equilibrium. Simulations for conditions corresponding to storage depths of 0.8−2.4 km revealed that after 1000 years, 65−75% of the SO₂ remains in the CO₂ phase. This slow release of SO₂ would largely mitigate its impact on brine pH. Furthermore, small amounts of SO₂ are predicted to have a negligible effect on the critical point of CO₂ but will increase phase density by as much as 12% for mixtures containing 5% SO₂ .

4. Ellis, B. R., Lauren E. Crandell, and Catherine A. Peters, 2008: Co-injection of SO₂ With CO₂ in Geological Sequestration: Potential for Acidification of Formation Brines. EOS Trans. AGU,
   [ Abstract ]

   Coal-fired power plants produce flue gas streams containing 0.02-1.4% SO₂ after traditional sulfur scrubbing techniques are employed. Due to the corrosive nature of H₂ SO₄ , it will likely be necessary to remove the residual SO₂ prior to carbon capture and transport; however, it may still be economically advantageous to reintroduce the SO₂ to the injection stream to mitigate the cost of SO₂ disposal and/or to get credits for SO₂ emissions reduction. This study examines the impact of SO₂ co-injection on the pH of formation brine. Using phase equilibrium modeling, it is shown that a CO₂ gas stream with 1% SO₂ under oxidizing conditions can create extremely acidic conditions (pH<1), but this will occur only near the CO₂ plume and over a short time frame. Nearly all of the SO₂ will be lost to the brine during this first phase equilibration, within approximately a decade, and the pH after the second is only 3.7, which is the pH that would occur from the carbonic acid alone. This suggests that although SO₂ will create low pH values due to the formation of H₂ SO₄ , the effect will have a very limited lifespan and a localized impact spatially. SO₂ is much more soluble than CO₂ and as the relative of amount of SO₂ to CO₂ is very small, the SO₂ will quickly dissolve into the formation brine. The extent of H₂ SO₄ formation is dependent on the redox conditions of the system. Several SO₂ oxidation pathways are investigated, including SO₂ disproportionation which produces both sulfate and the weaker acid, H₂ S. Further modeling considers a time varying, diffusion limited flux of SO₂ . Relative to the case of instantaneous phase equilibrium, this results in a smaller decrease in pH occurring over a longer duration. Our overall conclusion is that brine acidification due to SO₂ co-injection is not likely to be significant over relevant time and spatial scales.

5. Crandell, Lauren E., B. R. Ellis, and Catherine A. Peters, 0000: Dissolution Potential of SO₂ Co-Injected with CO₂ in Geologic Sequestration. Environmental Science and Technology, American Chemical Society, (44), doi:10.1021/es902612m 349-355
   [ Abstract ]

   Sulfur dioxide is a possible co-injectant with carbon dioxide in the context of geologic sequestration. Because of the potential of SO₂ to acidify formation brines, the extent of SO₂ dissolution from the CO₂ phase will determine the viability of co-injection. Pressure-, temperature-, and salinity-adjusted values of the SO₂ Henry’s Law constant and fugacity coefficient were determined. They are predicted to decrease with depth, such that the solubility of SO₂ is a factor of 0.04 smaller than would be predicted without these adjustments. To explore the potential effects of transport limitations, a nonsteady-state model of SO₂ diffusion through a stationary cone-shaped plume of supercritical CO₂ was developed. This model represents an end-member scenario of diffusion-controlled dissolution of SO₂, to contrast with models of complete phase equilibrium. Simulations for conditions corresponding to storage depths of 0.8—2.4 km revealed that after 1000 years, 65—75% of the SO₂ remains in the CO₂ phase. This slow release of SO₂ would largely mitigate its impact on brine pH. Furthermore, small amounts of SO₂ are predicted to have a negligible effect on the critical point of CO₂ but will increasephasedensity by asmuchas12% for mixtures containing 5% SO₂.

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