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PRINCETON - CMI REPRESENTATION AT GHGT-10

List of Princeton Participants, Schedule of Talks and Poster Presentations and Abstracts

International Conference on Greenhouse Gas Technologies (GHGT 10)

September 19-23, 2010, Amsterdam, The Netherlands

List of Princeton and affiliate contributors (C) and participants (P): Michael Celia (C, P) Benjamin Court (C, P) Mark Dobossy (C, P) Thomas Elliot (C,P) Brian Ellis (C, P) Sarah Gasda (C, P) John Higgins (C, P)

Mary Kang (P) Tom Kreutz (C, P) Eric Larson (C) Guangjian Liu (C) Ed Matteo (C, P) Jan Nordbotten (C, P) Juan Nogues (C, P)

Catherine Peters (C, P) George Scherer (C) Robert Socolow (P) James Wang (P) Robert Williams (C, P)


International Conference on Greenhouse Gas Technologies (GHGT 10) September 19-23, 2010, Amsterdam, The Netherlands

PRINCETON - CMI REPRESENTATION AT GHGT-10 Schedule of Talks and Poster Presentations:

September 21, 2010 0930 - 1050, Session 4C Modeling Tools Celia, Michael, Princeton University. “How Simple Can We Make Models for CO2 Injection, Migration, and Leakage?” 0930 - 1050, Session 10.01 Biomass and CCS Liu, Guangjian, Princeton University. “Design Economics of Low-Carbon Power Generation from Natural Gas and Biomass with Synthetic Fuels Co-production.”

1120 - 1240, Session 1.02 Mineralisation from Air House, Kurt Zenz, MIT. “The Use of Alkalinity Engineering for CO2 Mitigation.”

September 22, 2010 1120 – 1240, Session 4.01 CO2 Utilization, ECBM and Other Storage Options Kreutz, Tom, Princeton University. “Prospects for Producing Low Carbon Transportation Fuels from Captured CO2 in a Climate Constrained World.”

1340 - 1540, Poster Session 2 Developments in CO2 Storage Court, Ben, Princeton University. “Active and Integrated Management of Water Resources Throughout CO2 Capture and Sequestration Operations.” Dobossy, Mark, Princeton University, Geological Storage Consultants, LLC. “An Efficient Software Framework for Performing Industrial Risk Assessment of Leakage for Geological Storage of CO2.” Ellis, Brian, Princeton University. “Changes in Caprock Integrity due to Vertical Migration of CO2-Enriched Brine.”

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Gasda, Sarah, University of North Carolina at Chapel Hill. “The Impact of Local-Scale Processes on Large-Scale CO2 Migration and Immobilization.”

Matteo, Edward, Princeton University. “Understanding Boundary Condition Effects on the Corrosion Kinetics of Class H Well Cement.” Nogues, Juan, Princeton University. “Probability of Detecting CO2 Leakage in a Geological Sequestration Operation using Monitoring Wells.” Peters, Catherine, Princeton University. “LUCI: A Facility at DUSEL for Large-Scale Experimental Study of Geologic Carbon Sequestration.” 1540 – 1720, Session 1.19 Techno-Economic Comparisons Williams, Robert H., Princeton University. “Alternative Approaches for Decarbonizing Existing US Coal Power Plant Sites.”

September 23, 2010 0930 - 1050, Session 10D Wellbore Integrity Gasda, Sarah, University of North Carolina at Chapel Hill. “Analysis of In-Situ Wellbore Integrity Data for Existing Wells with Long-Term Exposure to CO2.”

Following are the Abstracts in Alphabetical Order by Main Author:













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GHGT-10

Active and integrated management of water resources throughout CO2 capture and sequestration operations

Benjamin Courta*, Michael A. Celiaa, Jan M. Nordbottena,b, Thomas R. Elliota aDepartment of Civil and Environmental Engineering, Princeton University, Princeton, NJ USA

bDepartment of Mathematics, University of Bergen, NORWAY

Elsevier use only: Received date here; revised date here; accepted date here

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.

© 2010 Elsevier Ltd. All rights reserved

Keywords: CO2 Capture and Sequestration, Water management, Brine production, Pressure management, Pore space competition


Energy Procedia


Available online at www.sciencedirect.com

GHGT-10

An efficient software framework for performing industrial risk assessment of leakage for geological storage of CO2

Mark E. Dobossya,b, Michael A. Celiaa,b, Jan M. Nordbottena,b,c aGeological Storage Consultants, LLC, 3794 McAndrews Road, Rosemount, MN USA

bDepartment of Civil and Environmental Engineering, Princeton University, Princeton, NJ USA cDepartment of Mathematics, University of Bergen, Bergen Norway


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 CO2 through 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. © 2010 Elsevier Ltd. All rights reserved

Keywords: Geological Storage of CO2; Leakage Along Wells; Analytical Models; Risk Assessment; Carbon Capture and Storage;

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�� Energy Procedia 00 (2010) 000–000



GHGT-10

Changes in caprock integrity due to vertical migration of CO2-enriched brine

Brian R. Ellis1, Grant S. Bromhal2, Dustin L. McIntyre2, Catherine A. Peters1*

1Department of Civil and Environmental Engineerging, Princeton University, Princeton, NJ 08544 2U.S. Department of Energy, National Energy Technology Laboratory, Morgantwon, WV 26507


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.


Keywords: Geologic carbon sequestration, Caprock integrity, Brine leakage, Carbonate caprock

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1

Analysis of in-situ wellbore integrity data for existing wells with long-term exposure to CO2

Sarah E. Gasdaa, James Z. Wangb, Michael A. Celiab

aEnvironmental Sciences and Engineering, University of North Carolina at Chapel Hill, 148

Rosenau Hall, Chapel Hill, NC 27560 USA bCivil and Environmental Engineering, Princeton University, Princeton, NJ 08540 USA

Abstract An important aspect of the risk associated with geological carbon dioxide sequestration is the integrity of existing wellbores that penetrate geological layers targeted for CO2 injection. CO2 leakage may occur through multiple pathways along a wellbore within the “disturbed zone” surrounding the well casing. The disturbed zone is defined as the annular region along the exterior of the steel wellbore casing that includes the Portland cement sheath, the damage zone of the host rock and the casing-cement-rock interfaces. The effective permeability of this zone is a key parameter of wellbore integrity required for validation of numerical models. Effective permeability may depend on a number of complex factors, including long-term attack by aggressive fluids, poor well completion or actions related to production of fluids through the wellbore. Field tests are essential to understanding the in situ leakage properties of the millions of wells that exist in mature sedimentary basins in North America. We present results from recent field studies of different CO2 producing wells from both natural CO2 reservoirs and enhanced oil recovery (EOR) operations. These surveys have included a particular downhole pressure test, the vertical interference test (VIT), designed to determine the extent of hydraulic communication along the exterior of the well casing. The VIT test involves perforating the well casing in two separate intervals, both of which are located within the shale caprock and bracket a zone of cement identified to have a lower quality bond. Once the intervals are isolated with an inflatable packer, the system is pressurized from surface and held at a constant pressure, while simultaneously, the transient pressure response is measured in the lower isolated interval. The pressure transient data is an indicator of the extent of hydraulic communication and is the focus of subsequent analysis. The effective wellbore permeability can be determined through numerical analysis of the VIT data. Our objective is to identify to most effective method of analysis for estimating wellbore permeability. We evaluate two different automated parameter estimation methods, nonlinear regression and shuffled complex evolution metropolis methods. Within this study, we also estimate parameters such as permeability and compressibility of the low permeability shale zone to determine their effect on the resulting estimate of wellbore permeability. The results of this work demonstrate that parameter estimation can be effective at identifying the key parameters associated with wellbore integrity from VIT field tests, and ultimately reducing the uncertainty regarding the integrity of existing wellbores.

Keywords: Wellbore integrity; parameter estimation; effective wellbore permeability

1

The impact of local-scale processes on large-scale CO2 migration and immobilization

Sarah E. Gasdaa, Jan M. Nordbottenb, Michael A Celia1

aEnvironmental Sciences and Engineering, University of North Carolina at Chapel Hill,

148 Rosenau Hall, Chapel Hill, NC 27560 USA bDepartment of Mathematics, University of Bergen, Bergen, Norway

1Civil and Environmental Engineering, Princeton University, Princeton, NJ 08540 USA

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 dissolution-convective 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 this modeling approach, we demonstrate the effect of different modeling choices associated with dissolution and capillary processes for typical large-scale geological systems.

Keywords: CO2 sequestration, upscaled models, capillary fringe, dissolution, convective mixing

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GHGT-10

The Use Alkalinity Engineering for CO2 Mitigation

Kurt Zenz Housea,c, Daniel P. Schrag,b John H. Higginsd, Elza Olivetti,e Christopher House,f Michael J. Azizg

aDepartment of Civil & Environment Engineering, Massachuetts Instiute of Technology bDepartment of Earth & Planetary Sciences, Harvard University,

cC12 Energy, Inc. dDepartmnet of Gecoscience, Princeton University

eDepartment of Material Science, Massachuetts Instiute of Technology FDepartment of Earth Science, Pennslyvania State University

GSchool of Engineering & Applied Science, Harvard University


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. © 2010 Elsevier Ltd. All rights reserved

Keywords: CO2 capture, air capture, alkalinity, geo engineering



EnergyProcedia


GHGT-10

Prospects for producing low carbon transportation fuels from captured CO2 in a climate constrained world

Tom Kreutz*

Princeton Environmental Institute, Princeton University, 25 Guyot Hall, Princeton, NJ 08544 USA


Abstract

The climate implications of technologies that capture CO2 to produce transportation fuels (CCTF) are investigated by study-ing two examples: biodiesel from microalgae and Sandia National Laboratory’s S2P process. Simple performance and economic models for each technology are examined in the context of a bifurcated – “pre-CCS” vs. “post-CCS” – climate regime in which CCTF uses CO2 that is captured from power plant flue gases or taken from CCS pipelines, respectively. CCTF promises to im-prove domestic energy security by converting sunlight and waste CO2 into transportation fuels; in addition, these fuels are roughly climate neutral when CO2 is captured from either flue gases or directly from the atmosphere. However, after the power sector becomes largely decarbonized under a stringent climate policy, large point sources of concentrated CO2 are likely to be relatively rare, and unfortunately, fuels made from pipeline CO2 destined for storage do not have markedly reduced net GHG emissions. Thus, absent the development of economical CO2 capture from air, it’s difficult to see how CCTF can play a signifi-cant long term role in decarbonizing the US transportation sector (and thus reaching US climate goals). © 2010 Elsevier Ltd. All rights reserved

Keywords: CO2 capture and reuse; microalgae biodiesel; S2P; transportation fuels; climate mitigation; CO2 capture and storage


Energy

ProcediaEnergy Procedia 00 (2010) 000–000


GHGT-10

Design/economics of low-carbon power generation from natural gas and biomass with synthetic fuels co-production

Guangjian Liu,1,a,b Robert H. Williams,a Eric D. Larson,a,c Thomas G. Kreutzaa Princeton Environmental Institute, Princeton University, Guyot Hall, Washington Rd, Princeton, NJ, 08544, USA

b School of Energy and Power Engineering, North China Electric Power University, Beijing 102206, China c Climate Central, 1 Palmer Square, Princeton, NJ, 08542, USA


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 co-production 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.


Keywords: biomass, co-production, CCS, economics, natural gas.

Energy Procedia



GHGT-10

Understanding Boundary Condition Effects on the Corrosion Kinetics of Class H Well Cement

Edward N. Matteo1, George W. Scherer2, Bruno Huet3, and Leo Pel41Princeton University, Department of Chemical Engineering, Eng. Quad. E-226, Princeton, NJ 08544 USA

2Princeton University, Department of Civil & Environmental Engineering, Eng. Quad. E-319 Princeton, NJ 08544 USA3Schlumberger Carbon Services, Schlumberger Riboud Product Center, 1, rue Henri Becquerel, BP202, 92142 Clamart Cedex, France

4Eindhoven University of Technology, Department of Physics, PO Box 513, 5600 MB, Eindhoven, the Netherlands


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.


Keywords : Acid leaching of Portland cement, carbonic acid, Class H well cement, geologic CO2 storage, wellbore integrity .


Energy Procedia


GHGT-10

Detecting leakage of brine or CO2 through abandoned wells in a geological sequestration operation using pressure monitoring wells

Juan P. Noguesa*, Jan M. Nordbottena,b and Michael A. Celiaa aPrinceton University, Dept. of Civil and Environmental Engineering, Princeton, NJ 08542, USA

bUniversity of Bergen, Faculty of Mathematics and Natural Sciences, Johannes Bruns gt. 12, Bergen, Norway Elsevier use only: Received date here; revised date here; accepted date here

Abstract

For risk assessment, policy design and GHG emission accounting it is extremely important to know if any CO2 or brine has leaked from a geological sequestration (GS) operation. As such, it is important to understand if it is possible to use certain technologies to detect it. This detection of leakage is one of the most challenging problems associated with GS due to the high uncertainty in the nature and location of leakage pathways. In North America for example millions of legacy oil and gas wells present the possibility of CO2 and brine to leak out of the injection formation. The available information for these potential leaky wells is very limited and the main parameters that control leakage, like permeability of the sealing material are not known. Here we propose to explore the possibility of detecting such leakage by the use of pressure-monitoring wells located in a formation overlying the injection formation. The detection analysis is based on a system of equations that solve for the propagation of a pressure pulse using the superposition principle and an approximation to the well function. We explore the questions of what can be gained by using pressure-monitoring wells and what are the limitations given a specific accuracy threshold of the measuring device. We also try to answer the question of where these monitoring wells should be placed to optimize the objective of a monitoring scheme. We believe these results can ultimately lead to practical design strategies for monitoring schemes, including quantitative estimation of increased probability of leak detection per added observation well. © 2010 Elsevier Ltd. All rights reserved

Keywords: Leakage Detection, Abandoned Wells

Energy Procedia




GHGT-10

LUCI: A facility at DUSEL for large-scale experimental study of geologic carbon sequestration

Catherine A. Petersa,*, Patrick F. Dobsonb, Curtis M. Oldenburgb, Joseph S. Y. Wangb, Tullis C. Onstotta, George W. Scherera, Barry M. Freifeldb, T.S. Ramakrishnanc,

Eric L. Stabinskic, Kenneth Liangc, Sandeep Vermac aDept. of Civil & Environmental Engineering, Princeton University, Princeton, NJ 08544 USA

bEarth Sciences Division 90-1116, Lawrence Berkeley National Laboratory, Berkeley CA 94720 USA cSchlumberger-Doll Research Center, 1 Hampshire Street, Cambridge, MA 02139 USA


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. © 2010 Elsevier Ltd. All rights reserved

Keywords: Leakage; buoyancy; Joule-Thomson; experimental; storage



EnergyProcedia


GHGT-10

Alternatives for Decarbonizing Existing USA Coal Power Plant Sites

Robert H Williamsa,1*, Guangjian Liua,b, Thomas G Kreutza, and Eric D Larsona,c a Princeton Environmental Institute, Princeton University, Guyot Hall, Washington Rd, Princeton, NJ, 08544, USA

b School of Energy and Power Engineering, North China Electric Power University, Beijing 102206, China c Climate Central, 1 Palmer Square, Princeton, NJ, 08542, USA


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, © 2010 Elsevier Ltd. All rights reserved

Keywords: coal; biomass; co-production; CCS; economics

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