Bibliography - Catherine A. Peters

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. Kim, D., Catherine A. Peters, and W. B. Lindquist, 2011: Upscaling geochemical reaction rates accompanying acidic CO₂-saturated brine flow in sandstone aquifers. Water Resources Research, American Geophysical Union, 47, W01505, doi:10.1029/2010WR009472 1-16
   [ Abstract ]

   Network flow models were used to simulate the flow of CO₂-saturated brine in the pore networks corresponding to three different sandstones. The simulations were used to study upscaling of anorthite and kaolinite reaction rates from pore to core scales. Unique to our simulations is the use of computed tomography to capture the mineral distribution in the samples as well as the sample pore network. The upscaled reaction rates determined from these simulations incorporate mass balance principles and microscale reaction rate laws and capture the physical, mineral, and flow heterogeneities in the network. These upscaled rates were compared with upscaled rates predicted by a continuum model and by a volumeaveraged- concentration method. For the anorthite reaction, which remains far from equilibrium, the volume-averaged reaction rate exceeded the reaction rate of the network model by 18% to 46%. While the continuum model rate also exceeded the network model rate by −1% to 53%, its predicted values were generally better than the volume-averaged method. The kaolinite reaction is near equilibrium and is heavily influenced by the form of the microscale rate law in the precipitation regime. Three alternate rate laws were tested, which produced significantly different predictions for the bulk reaction rates. For all three rate laws, continuum and volume-averaged reaction rates incorrectly predicted the magnitude of the kaolinite reaction rate (disagreements of −700% to 55%), and the predicted reaction type, dissolution versus precipitation, was also often opposite to that of the network model. Finally, for both anorthite and kaolinite, all upscaled reaction rates showed significant flow rate dependence.

3. Peters, Catherine A., P. F. Dobson, C. M Oldenburg, Joseph S.Y. Wang, T. C. Onstott, George Scherer, B. Freifeld, T. S. Ramakrishnan, Eric L. Stabinski, Kenneth Liang, and Sandeep Verma, 2011: LUCI: A facility at DUSEL for large-scale experimental study of geologic carbon sequestration. Energy Procedia, Elsevier, 4, doi:10.1016/j.egypro.2011.02.478 5050-5057
   [ Abstract ]

   LUCI, the Laboratory for Underground CO₂ Investigations, is an experimental facility being planned for the DUSEL underground laboratory in South Dakota, USA. It is designed to study vertical flow of CO₂ in porous media over length scales representative of leakage scenarios in geologic carbon sequestration. The plan for LUCI is a set of three vertical column pressure vessels, each of which is ∼500 m long and ∼1 m in diameter. The vessels will be filled with brine and sand or sedimentary rock. Each vessel will have an inner column to simulate a well for deployment of down-hole logging tools. The experiments are configured to simulate CO₂ leakage by releasing CO₂ into the bottoms of the columns. The scale of the LUCI facility will permit measurements to study CO₂ flow over pressure and temperature variations that span supercritical to subcritical gas conditions. It will enable observation or inference of a variety of relevant processes such as buoyancy-driven flow in porous media, Joule-Thomson cooling, thermal exchange, viscous fingering, residual trapping, and CO₂ dissolution. Experiments are also planned for reactive flow of CO₂ and acidified brines in caprock sediments and well cements, and for CO₂-enhanced methanogenesis in organic-rich shales. A comprehensive suite of geophysical logging instruments will be deployed to monitor experimental conditions as well as provide data to quantify vertical resolution of sensor technologies. The experimental observations from LUCI will generate fundamental new understanding of the processes governing CO₂ trapping and vertical migration, and will provide valuable data to calibrate and validate large-scale model simulations.

4. 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.

5. Peters, Catherine A., P. F. Dobson, C. M Oldenburg, Joseph S.Y. Wang, and George Scherer, 2010: LUCI: A Facility at DUSEL for Large-Scale Experimental Study of Geologic Carbon Sequestration. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   LUCI, the Laboratory for Underground CO₂ Investigations, is an experimental facility being planned for the DUSEL underground laboratory in South Dakota, USA. It is designed to study vertical flow of CO₂ in porous media over length scales representative of leakage scenarios in geologic carbon sequestration. The plan for LUCI is a set of three vertical column pressure vessels, each of which is ~500 m long and ~1 m in diameter. The vessels will be filled with brine and sand or sedimentary rock. Each vessel will have an inner column to simulate a well for deployment of down-hole logging tools. The experiments are configured to simulate CO₂ leakage by releasing CO₂ into the bottoms of the columns. The scale of the LUCI facility will permit measurements to study CO₂ flow over pressure and temperature variations that span supercritical to subcritical gas conditions. It will enable observation or inference of a variety of relevant processes such as buoyancy-driven flow in porous media, Joule- Thomson cooling, thermal exchange, viscous fingering, residual trapping, and CO₂ dissolution. Experiments are also planned for reactive flow of CO₂ and acidified brines in caprock sediments and well cements, and for CO₂ -enhanced methanogenesis in organic-rich shales. A comprehensive suite of geophysical logging instruments will be deployed to monitor experimental conditions as well as provide data to quantify vertical resolution of sensor technologies. The experimental observations from LUCI will generate fundamental new understanding of the processes governing CO₂ trapping and vertical migration, and will provide valuable data to calibrate and validate large-scale model simulations.

6. 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 .

7. Peters, Catherine A., George Scherer, Michael Celia, Jean Hervé Prévost, T. C. Onstott, P. F. Dobson, C. M Oldenburg, B. Freifeld, J. Birkholzer, J. Wang, S. Benson, and T. J. Phelps, et al., in press: Collaborative Research: DUSEL CO₂, A Deep Underground Laboratory for Geologic CO₂ Sequestration Studies: A proposal for the conceptual design of the facility and experiments. NSF. 0/09.
   [ Abstract ]

   Princeton University and Lawrence Berkeley National Laboratory have forged a new collaboration to examine the feasibility and risks of carbon sequestration, a method of countering global warming by storing greenhouse gases deep underground. To develop a sound understanding of carbon sequestration, we will build a deep underground laboratory to study the processes of trapping and storing CO₂, including the risks of unintended leakage. It will be part of the new DUSEL facility at the Homestake mine in South Dakota. The “DUSEL CO₂, facility will make the United States the only country with a deep underground laboratory for controlled study of geologic carbon sequestration, providing a unique opportunity for global leadership. The findings from these unique experiments will advance carbon management technology worldwide and help reduce global greenhouse gas emissions. The features and capabilities of the planned facility are unprecedented. The experimental design exploits the nearly half-kilometer vertical extent of existing “sandline” borings at Homestake. Pipes will be installed within the sandlines to serve as long flow columns. These columns will contain the CO₂, and allow experimentation at the same pressure and temperature conditions as in deep subsurface reservoirs. Fill materials will mimic sedimentary layering, as well as cements in plugged wells. Instrumentation will enable detailed monitoring of flow, pressure, temperature, brine composition, geomechanics, and microbial activity. As part of the initial suite of experiments, we plan to simulate a leak in which CO₂, changes from a supercritical fluid to a subcritical gas as the pressure drops during upflow over tens to hundreds of meters. We will test for possible acceleration in CO₂, flow due to increasing buoyancy. Also, we will examine the interactions of CO₂, with cap-rocks and well cements, and determine whether CO₂, will enlarge flow pathways or cause selfsealing. Finally, we will investigate the effects of anaerobic, thermophilic bacteria on CO₂, conversion to methane and carbonate. This project is being led by researchers at Princeton and LBNL, and involves no-cost collaboration with individuals at ORNL, Stanford University, Schlumberger and the U.S. DOE NETL. During this three-year project, the team is working to (i) prioritize future experiments that will be conducted at DUSEL CO₂, (ii) build models that simulate experimental conditions and predict process dynamics, and (iii) develop a Work-Breakdown Structure (WBS) schedule for design, procurement, construction, operation and deconstruction of the facility over the facility lifetime. International awareness about DUSEL CO₂, is being fostered through international workshops and formation of an International Advisory Committee. Also, we are collaborating with other DUSEL scientists on education and outreach about “deep science,” with particular focus on climate change and energy solutions. DUSEL education and outreach activities are focused on Native American communities in South Dakota and operation of the Visitor Center at the Sanford Lab at Homestake. To inspire and educate the next generation of leaders, we are involving undergraduate and graduate students in DUSEL CO₂, research at Princeton University.

8. 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.

9. Peters, Catherine A., 2008: Accessibilities of reactive minerals in consolidated sedimentary rock: An imaging study of three sandstones. Chemical Geology, doi:10.1016/j.chemgeo.2008.11.014
   [ Abstract ]

   Widespread implementation of geological storage of CO₂ requires an understanding of dissolution reactions with formation minerals. This will be aided by reactive transport modeling, which relies on accurate estimates of the accessible surface areas of reactive minerals in consolidated sedimentary rocks. For three Viking sandstones (Alberta sedimentary basin, Canada), we have employed backscattered electron microscopy and energy dispersive X-ray spectroscopy to examine mineral content and to statistically characterize mineral contact with pore space. Porosities range from 20% in a lightly-cemented sandstone with grains on the order of 100 ìm, to 8% in a highly-cemented shaly sandstone with a mix of primary pore space and fractures, to 7% in a lightly-cemented conglomerate sandstone with grain sizes between 500 ìm and 1 mm. In all three specimens, kaolinite is the primary authigenic clay mineral cementing quartz grains. It accounts for only 5% to 31% of mineral content, but 65% to 86% of pore-mineral contact boundaries. The sandstone specimen has 6% minerals in the “reactive” category, which in this study includes minerals other than kaolinite and quartz, such as K-feldspar, apatite and pyrite. For this specimen, only one third of the reactive minerals are accessible to pore fluids due to clay-mineral grain coatings. For the shaly sandstone, only one fifth of its 5% reactive minerals are accessible to pore fluids due to regions of cementation of fine detrital matrix. Thus, if a mineral volume fraction is used in reactive transport modeling as a proportional measure of accessible surface area in consolidated sandstones, the reaction rates are likely to be overestimated by three to five times. The conglomerate sandstone has only 1% of its mineral matter in this category, and these are often found as inclusions rather than grains.

10. Peters, Catherine A., W. B. Lindquist, and Michael Celia, March 2008: Up-Scaling Mineral Accessibility and Pore Networks for CO₂ Reactive Transport in Sandstones. Global Change Biology,
    [ Abstract ]

    Widespread implementation of geological storage of CO₂ will require an understanding of acid-driven reactions with formation minerals. Predicting these reactions and their time scales requires rate laws that are appropriate for sedimentary rocks and estimates of accessible surface areas of reactive minerals. This project addresses these needs through a study that combines imaging of sandstone pore structure and minerals, and network-modeling of reaction rates in porous media. Rock specimens come from the Viking formation in the Alberta Sedimentary Basin. Imaging methods include X-ray computed microtomography (CT), backscatter electron microscopy (BSE) and energy dispersive X-ray (EDX) spectroscopy.
    One important goal is to characterize pore contact with individual minerals thereby quantifying meaningful surface areas for use in reactive transport models. The suite of techniques employed and the innovative means by which the images are collectively interpreted provides a wealth of information to address this goal. For example, a novel method of interpreting BSE images (which are high resolution) combined with EDX images (which can generate mineral maps) leads to 2D images that provide detailed characterization of the proximity of reactive minerals to pore space. Extension of this image processing approach to 3D, using CT images to broadly classify mineral categories, allows us to relate detailed information about pore structure with mineral accessibility, albeit with coarser resolution.
    All the specimens are sandstones of comparable porosity and grain diameter, and yet order of magnitude variation is found in pore structure and reactive mineral properties across them. In general, we have found that mineral volumetric content is a poor indicator of proportionate poreto- mineral surface area due to the means by which minerals are obscured in consolidated media. For example, kaolinite and other authigenic clay minerals that coat grains and fill primary pore space account for only 5% to 30% of mineral content, but 65% to 90% of pore-mineral contact boundaries. Minerals that would react under acidic conditions may account for 5% to 10% (vol.) of mineral matter, but if these percentages are used to apportion surface area, they would overestimate reaction rates by three to five times.
    These detailed characterizations of pore structure and mineral spatial patterning are being used to develop pore-network models that simulate reactive transport. Simulations of conditions representative of COWidespread implementation of geological storage of CO2 will require an understanding of acid-driven reactions with formation minerals. Predicting these reactions and their time scales requires rate laws that are appropriate for sedimentary rocks and estimates of accessible surface areas of reactive minerals. This project addresses these needs through a study that combines imaging of sandstone pore structure and minerals, and network-modeling of reaction rates in porous media. Rock specimens come from the Viking formation in the Alberta Sedimentary Basin. Imaging methods include X-ray computed microtomography (CT), backscatter electron microscopy (BSE) and energy dispersive X-ray (EDX) spectroscopy. One important goal is to characterize pore contact with individual minerals thereby quantifying meaningful surface areas for use in reactive transport models. The suite of techniques employed and the innovative means by which the images are collectively interpreted provides a wealth of information to address this goal. For example, a novel method of interpreting BSE images (which are high resolution) combined with EDX images (which can generate mineral maps) leads to 2D images that provide detailed characterization of the proximity of reactive minerals to pore space. Extension of this image processing approach to 3D, using CT images to broadly classify mineral categories, allows us to relate detailed information about pore structure with mineral accessibility, albeit with coarser resolution. All the specimens are sandstones of comparable porosity and grain diameter, and yet order of magnitude variation is found in pore structure and reactive mineral properties across them. In general, we have found that mineral volumetric content is a poor indicator of proportionate poreto- mineral surface area due to the means by which minerals are obscured in consolidated media. For example, kaolinite and other authigenic clay minerals that coat grains and fill primary pore space account for only 5% to 30% of mineral content, but 65% to 90% of pore-mineral contact boundaries. Minerals that would react under acidic conditions may account for 5% to 10% (vol.) of mineral matter, but if these percentages are used to apportion surface area, they would overestimate reaction rates by three to five times. These detailed characterizations of pore structure and mineral spatial patterning are being used to develop pore-network models that simulate reactive transport. Simulations of conditions representative of CO₂ injection for geological storage are being used to examine up-scaling of reaction rates from the pore-scale to the core-scale.

11. Peters, Catherine A., J. A. Lewandowski, M. L. Maier, Michael Celia, and , 2006: Mineral Grain Spatial Patterns and Reaction Rate Up-Scaling. Proceedings of the XVI Intl Conf on Computational Methods in Water Resources, Copenhagen, http://esd.lbl.gov/ESD_staff/li_li/lilicmwrxviCAP.pdf,
    [ Abstract ]

    Reactive transport models that describe mineral reactions in porous media rely on laboratory measurements of rate parameters that may fail to represent reactions defined at larger averaging scales. In recently completed work, we used pore-scale network models to investigate the effects of heterogeneities in pore structure and mineral distribution on geochemical reaction rates in porous media. Our findings revealed significant scaling effects from variations in reactive mineral distribution, especially for the highly acidic conditions encountered in geological sequestration of carbon dioxide. In this paper we present preliminary findings from electron scanning BSE maps, to analyze spatial patterns of minerals in sedimentary rocks. Samples include sandstones from the Viking formation in the Alberta basin in western Canada. Image analysis was used to quantify pore space and examine reactive minerals in relation to pore locations. Typically, reactive minerals occur as distinct grains and inclusions, and their percent abundance is larger than the extent of their contact with pore fluids.

12. Bruant, R., D. E. Giammar, S.C.B. Myneni, and Catherine A. Peters, October 2002: Effect of pressure, temperature, and aqueous carbon dioxide concentration on mineral weathering as applied to geologic storage of carbon dioxide. Proceedings of the 6th International Conference on Greenhouse Gas Control Technologies (GHGT-6), http://www.princeton.edu/~cmi/research/kyoto02/bruant%20et%20al.kyoto%2002.pdf,
    [ Abstract ]

    CO₂ mediated dissolution of silicate minerals and subsequent precipitation of carbonates in deep saline aquifers may allow permanent trapping of carbon dioxide. However, the time-scales and extents of the reactions are poorly understood for CO₂ receptor formation conditions. To address these shortcomings, experiments were conducted to investigate the effects of pressure, temperature, and aqueous solution composition on rates and mechanisms of silicate mineral dissolution and carbonate precipitation. A high pressure/high temperature flow-through reactor system was used to derive steady-state dissolution rates of crushed forsteritic olivine. The system allowed continuous monitoring of temperature, pressure, and pH, and periodic sampling of effluent fluids for dissolved ion concentration analysis. Preliminary measurements of dissolution rates indicate good agreement with previously published measurements at ambient conditions. Increasing the pressure from 1 to 100 bar under constant CO₂ conditions increased the dissolution rate by ~80%. The same reactions were studied in batch systems using an array of analytical techniques to investigate dissolution mechanisms and secondary precipitate formation. The extent of olivine dissolution in the batch reactors increased with temperature, PCO₂, and surface area. Precipitation of magnesium-rich carbonates on reacted olivine was observed at initial magnesite saturation indices greater than 1.6.

13. Bruant, R., A. J. Guswa, Michael Celia, and Catherine A. Peters, 2002: Safe Storage of Carbon Dioxide in Deep Saline Aquifers. Environmental Science and Technology, 36(11), doi:10.1021/es0223325 240A-245A
    [ Abstract ]

    Over the past 420,000 years, global average atmospheric CO₂ concentrations have fluctuated narrowly between 180 and 280 parts per million by volume (ppmv), but since the Industrial Revolution, CO₂ concentrations have increased to ~370 ppmv. This increase is believed to be contributing to risingmean global temperatures (1, 2). Average annual global anthropogenic CO₂ emissions during the 1990s were ~27 GtCO₂/yr (1 GtCO₂ = 109 metric tons of CO₂ = 10¹² kg of CO₂ = 0.27 GtC). The Intergovernmental Panel on Climate Change estimates that under a “business-as- usual” energy scenario, global emissions will reach ~77 GtCO₂/yr by 2100, and the average atmospheric CO₂ concentration will reach ~750 ppmv (2). To stabilize atmospheric CO₂ concentrations at 550 ppmv, which is approximately twice preindustrial concentrations, global emissions must be continuously reduced so that by 2050, global emissions are 15 GtCO₂/yr less than the business-as-usual projection, and by 2100, emissions are 50 GtCO₂/yr less (2, 3).

14. Bruant, R., R. J. Held, Catherine A. Peters, and Michael Celia, 2001: Pore Scale Network Simulation of Single and Multiple Component Non-Aqueous Phase Luquid (NAPL) Dissolution. American Geophysical Union,
    [ Abstract ]

    A computational three-dimensional pore-scale network model was used to quantify residual single- and multi-component non-aqueous phase liquid (NAPL) dissolution driven by aqueous-phase advection. The pore network was discretized into spherical pore bodies and biconical pore throats to represent the effective void space and void distribution of a fine-grained Ottawa sand. Fluid saturations, positions, and interfacial areas, in addition to aqueous-phase flow, were established by externally applied pressure gradients. Mass transfer from the NAPL to the aqueous phase was computed as a local flux across each interface using a stagnant boundary layer Fickian diffusion model. Subsequent mass transport in the aqueous phase was simulated by a volume-conserving characteristic method along streamlines. The model dynamically calculated interface retraction resulting from mass transfer between the non-aqueous and aqueous phases, and concurrently tracked physical changes in NAPL saturation, NAPL composition, and interfacial geometry. The model avoids scale inconsistencies, allowing pore-scale through continuum-scale description of NAPL dissolution. In this presentation, results from NAPL dissolution simulations will be compared (as a function of saturation and location) to laboratory experiments and implications for up-scaling mass transfer coefficients will be discussed. Dependence of multi-component NAPL composition on mass transfer phenomena and differences between single- and multi-component systems also will be highlighted.

15. 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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