International Conference on Greenhouse Gas Technologies (GHGT 10)

1. Dobossy, M., Michael Celia, and Jan M. Nordbotten, 2011: An Efficient Software Framework for Performing Industrial Risk Assessment of Leakage for Geological Storage of CO₂. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia, doi:10.1016/j.egypro.2011.02.368 4207-4214
   [ Abstract ]

   In response to anthropogenic CO₂ emissions, geological storage has emerged as a practical and scalable bridge technology while renewables and other environmentally friendly energy production methods mature. While an attractive solution, geological storage of CO₂ has inherent risk. Two primary concerns are recognized: 1) leakage of CO₂through caprock imperfections, and 2) brine displacement resulting in contamination of drinking water sources. Three mechanisms for both CO₂ and brine leakage have been identified: diffuse leakage through the caprock, leakage through faults and fractures in the caprock, and finally, leakage through man-made pathways such as abandoned wells from oil and gas exploration. While the first two leakage mechanisms are important, we emphasize the risks associated with the presence of abandoned wells. This is due to the large number and density of wells from a history of oil and gas exploration around the world, and the high degree of uncertainty surrounding the properties of these abandoned wells. With current proposed legislation in both the United States and Europe, a need is emerging for practical assessment of leakage risk. In order to accurately predict leakage of brine and CO₂ from the injection layer, the geological information for the injection site and the location and makeup of the man-made leakage pathways previously alluded to must be taken into account. Unfortunately, both the geology and abandoned well metadata are typically high in uncertainty, which must be accounted for. With such a high number of random variables, the current state of the art is running many realizations of a system, using a Monte Carlo approach. This requires that the underlying solution algorithms be accurate, and efficient. In the past, many researchers in both academia and industry have turned to robust numerical analysis packages used in the oil industry. However, due to the large range of scales important to this problem (domains of tens of kilometers on a side affected by leakage pathways with diameters of tens of centimeters) such modeling techniques become computationally expensive for all but the most basic analysis. A computational model developed at Princeton University, and currently being commercialized by Geological Storage Consultants, LLC has been shown to be efficient with sufficient accuracy to allow for comprehensive risk assessment of CO₂ injection projects. The model allows for mixing solution methods- using computationally expensive algorithms for formations of greater importance (e.g.- the injection formation) and more efficient, simplified algorithms in other areas of the domain. This ability to arbitrarily mix solution methods offers significant flexibility in the design and execution of models. This paper addresses the framework and algorithms used, and illustrates the importance of efficiency and parallelism using the case study of an injection site in Alberta, Canada. We show how the framework can be used for project planning, for risk mitigation (insurance), and for regulatory groups. Finally, the importance of flexible analysis tools that allow for efficient and effective management of computational resources is discussed.

2. Gasda, S., Jan M. Nordbotten, and Michael Celia, 2011: The impact of local-scale processes on large-scale CO₂ migration and immobilization. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia, doi:10.1016/j.egypro.2011.02.327 3896-3903
   [ Abstract ]

   Storage security of injected carbon dioxide (CO₂) is an essential component of risk management for geological carbon sequestration operations. During the injection and early post-injection periods, CO₂ leakage may occur along faults and leaky wells, but this risk may be partly managed by proper site selection and sensible deployment of monitoring and remediation technologies. On the other hand, long-term storage security is an entirely different risk management problem—one that is dominated by a mobile CO₂ plume that may travel over very large spatial distances, over long time periods, before it is trapped by a variety of different physical and chemical processes. In the post-injection phase, the mobile CO₂ plume migrates in large part due to buoyancy forces, following the natural topography of the geological formation. The primary trapping mechanisms are capillary and solubility trapping, which evolve over thousands to tens of thousands of years and can immobilize a significant portion of the mobile, free-phase CO₂ plume. However, both the migration and trapping processes are inherently complex, involving a combination of small and large spatial scales and acting over a range of time scales. Solubility trapping is a prime example of this complexity, where small-scale density instabilities in the dissolved CO₂ region leads to convective mixing that has that has a significant effect on the large-scale dissolution process over very long time scales. Another example is the effect of capillary forces on the evolution of mobile CO₂, an often-neglected process except with regard to residual trapping. As the plume migrates due to buoyancy and viscous forces, local capillary effects acting at the CO₂-brine interface lead to a transition zone where both fluids are present in the mobile state. This small-scale effect may have a significant impact on large-scale plume migration as well as long-term residual and dissolution trapping. Using appropriate models that can capture both large and small-scale effects is essential for understanding the role of these processes on the long-term storage security of CO₂ sequestration operations. There are several approaches to modeling long-term CO₂ trapping mechanisms. One modeling option is the use of traditional numerical methods, which are often highly sophisticated models that can handle multiple complex phenomena with high levels of accuracy. However, these complex models quickly become prohibitively expensive for the type of large-scale, long-term modeling that is necessary for risk assessment applications such as the late post-injection period. We present an alternative modeling option that combines vertically-averaged governing equations with an upscaled representation of the dissolutionconvective mixing process and the local capillary transition zone at the CO₂-brine interface. CO₂ injection is solved numerically on a coarse grid, capturing the large-scale injection problem and the post-injection capillary trapping, while the upscaled dissolution and capillary fringe models capture these subscale effects and eliminate the need for expensive grid refinement to capture the subscale instabilities associated with convective mixing or the details of the capillary transition zone. With thismodeling approach, we demonstrate the effect of different modeling choices associated with dissolution and capillary processes for typical large-scale geological systems.

3. Court, Benjamin, Michael Celia, Jan M. Nordbotten, and Thomas R. Elliot, 2010: Active and Integrated Management of Water Resources Throughout CO₂ Capture and Sequestration Operations. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   Most projected climate change mitigation strategies will require a significant expansion of CO₂ Capture and Sequestration (CCS) in the next two decades. Four major categories of challenges are being actively researched: CO₂ capture cost, geological sequestration safety, legal and regulatory barriers, and public acceptance. Herein we propose an additional major challenge category across all CCS operations: water management. For example a coal-fired power plant retrofitted for CCS requires twice as much cooling water as the original plant. This increased demand may be accommodated by brine extraction and treatment, which would concurrently function as large-scale pressure management and a potential source of freshwater. At present the interactions among freshwater extraction, CO₂ injection, and brine management are being considered too narrowly -in the case of freshwater almost completely overlooked- in the technical and regulatory CCS community. This paper presents an overview of each of these challenges and potential integration opportunities. Active management of CCS operations through an integrated approach -including brine production, treatment, use for cooling, and partial reinjection- can address challenges simultaneously with several synergistic advantages. The paper also considers the related potential impacts of pore space competition (with future groundwater use, gas storage and shale gas) on CCS expansion. Freshwater and brine must become key decision making inputs throughout CCS operations, building on existing successful industrial-scale integrations.

4. House, Kurt Z., D. P. Schrag, John D. Higgins, and Elza Olivetti, 2010: The Use of Alkalinity Engineering for CO₂ Mitigation. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   We describe an approach to CO₂ capture and storage from the atmosphere that involves enhancing the solubility of CO₂ in the ocean by a process equivalent to the natural silicate weathering reaction. HCl is electrochemically removed from the ocean and neutralized through reaction with silicate rocks. The increase in ocean alkalinity resulting from the removal of HCl causes atmospheric CO₂ to dissolve into the ocean where it will be stored primarily as HCO3 - without further acidifying the ocean. On timescales of hundreds of years or longer, some of the additional alkalinity will likely lead to precipitation or enhanced preservation of CaCO3, resulting in the permanent storage of the associated carbon, and the return of an equal amount of carbon to the atmosphere. Whereas the natural silicate weathering process is effected primarily by carbonic acid, the engineered process accelerates the weathering kinetics to industrial rates by replacing this weak acid with HCl. In the thermodynamic limit—and with the appropriate silicate rocks—the overall reaction is spontaneous. A range of efficiency scenarios indicates that the process should require 100 - 400 kJ of work per mol of CO₂ captured and stored for relevant timescales. The process can be powered from stranded energy sources too remote to be useful for the direct needs of population centers. It may also be useful on a regional scale for protection of coral reefs from further ocean acidification. Application of this technology may involve neutralizing the alkaline solution that is co-produced with HCl with CO₂ from a point source or from the atmosphere prior to being returned to the ocean.

5. Liu, Guangjian, Robert H. Williams, Eric Larson, and Thomas Kreutz, 2010: Design Economics of Low-Carbon Power Generation from Natural Gas and Biomass with Synthetic Fuels Co-Production. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   There is growing optimism about the prospects for large natural gas reserves in shale formations. This paper explores the feasibility vis-à-vis coal power generation of a new approach for decarbonized natural gas power generation. Key features of process designs examined here are coproduction of synthetic transportation fuels with electricity and co-feeding of some biomass with natural gas in such co-production systems. Key questions addressed in the analysis of these systems are: 1) can the competitiveness of natural gas in economic dispatch be improved vis-à-vis a natural gas combined cycle, and 2) can the GHG emissions price needed to induce CCS for natural gas power generation be reduced from that required to induce CCS for NGCC. We find that gas/biomass co-production systems with CCS will be able to defend high capacity factors in economic dispatch at projected oil prices with only modest GHG emission prices. We also find that the breakeven GHG emission price needed to induce CCS for natural gas power generation is reduced considerably vis-à-vis NGCC-CCS.

6. Matteo, Edward, George Scherer, Bruno M. Huet, and Leo Pel, 2010: Understanding Boundary Condition Effects on the Corrosion Kinetics of Class H Well Cement. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   Storing carbon dioxide in depleted petroleum reservoirs is a viable strategy for carbon mitigation, but ensuring that the sequestered CO₂ remains in the formation is vital to the success of such projects. There is great concern for the development of leakage pathways through annuli between the well cement and the formation or the casing. Predicting the behavior of such potential leakage pathways is critical. Numerical simulations conducted using a reactive transport module match well with experimental studies [1], but also show the necessity of quantifying the transport and mechanical properties of the leached solid cementitious solids -- predominantly silica gel -- produced by carbonic acid corrosion of well cement. Bench-top experiments have been performed with the following goals in mind: 1) to investigate the parameter space of relevant corrosion boundary conditions, e.g. pH, CO₂ concentration, and calcium ion concentration, 2) to produce samples that can be used to quantify the transport and mechanical properties of acid corroded Class H well cement, and 3) to validate and improve the accuracy of numerical simulations of the reaction of well cement with carbonic acid. Class H cement samples were uniaxially corroded via exposure to a brine of constant composition. Constant composition is ensured by constant renewal of the brine at a rate larger than cement reaction rate. H⁺, Ca2+ and CO₂ total aqueous concentration in the NaCl brine are controlled independently by adding known amounts of NaCl, HCl, CaCl₂ and NaHCO₃ and by controlling CO₂ partial pressure. Microscopic (30X) time-lapse videos were taken of each sample so that corrosion front movements could be accurately measured. These experiments have yielded corrosion front measurements that clearly show that corrosion front advancement is diffusion controlled (i.e., linear as a function of the square root of time). The uniaxial corrosion of these samples has not only allowed for detailed measurements of the corrosion front, but also affords the opportunity to measure the mechanical properties of the corroded samples as a function of depth. The one-dimensional corrosion also allows for measuring the diffusion coefficient of the outer layer of silica gel by low field Nuclear Magnetic Resonance (NMR). Measuring the kinetics under various boundary conditions has validated the modeling results reported by Huet et al. [1]. The measurements of mechanical and transport properties can now be used to improve the predictive power of these simulations by providing much needed information on the exterior layer of corroded Class H well cement. Additionally, these experiments offer experimental validation that the corrosion kinetics are enhanced by the presence of CO₂ and open the door to better understanding of the mechanism of, and boundary conditions that might lead to, “pore-plugging” by the corrosion products, which in turn leads to a drastic retardation of the corrosion reaction.

7. 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.

8. Williams, Robert H., Guangjian Liu, Thomas Kreutz, and Eric Larson, 2010: Alternatives for Decarbonizing Existing USA Coal Power Plant Sites. International Conference on Greenhouse Gas Technologies (GHGT 10), Elsevier/Energy Procedia,
   [ Abstract ]

   A CO₂ capture and storage (CCS) retrofit strategy is compared to several repowering strategies for decarbonising existing coal power plant sites. The more promising repowering approaches analyzed seem to be a shift to natural gas via natural gas combined cycles and deployment of systems that coproduce synthetic liquid fuels plus electricity from coal and biomass with CCS. Under a wide range of plausible conditions, the latter option seems to the most promising approach for decarbonising these plant sites—exploiting simultaneously the carbon mitigation benefit of coprocessing biomass in CCS energy systems and the more general benefits offered by coproduction systems with CCS of: (i) a low CO₂ capture cost, (ii) a high efficiency of power generation, and (iii) large credit for the sale of the synfuel coproducts at current or higher oil prices.

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