Geological Storage Of Carbon Dioxide Research Articles

Geological storage of carbon dioxide: an emerging opportunity

Abstract Concerns about climate change and the need to stabilize atmospheric CO 2 concentrations are driving the development of a lower carbon future. Within this context, carbon dioxide capture and storage (CCS) is gaining momentum as a large-scale option to reduce greenhouse gas emissions. This paper reviews the rationale and potential scale of CCS, the status of geological storage options and lessons from the operating In Salah project. CCS is expected to have applications in the oil and gas industry, and other industries, particularly the coal and power sectors. CO 2 -enhanced oil recovery, depleted oil and gas fields and saline formations are considered the most important geological storage options. Experience with geological storage is being gained at the In Salah project in Algeria. Operating since 2004, it is the world's first industrial-scale project storing CO 2 in the water leg of a gas reservoir. A key challenge for wider deployment is for geological storage to be accepted as a safe and effective option, providing long-term CO 2 containment, with high integrity. This has several associated technical and regulatory challenges, including site characterization and selection, geological and well integrity risk assessment, performance prediction, the design of appropriate monitoring schemes and handling the closure and post-closure phases. The petroleum industry has the capabilities and know-how to deploy CCS and to manage the associated risks. This lends confidence that CCS will be a viable option and that deployment will help enable a low-carbon future.

ＣＯ２地中貯留への取組 ＣＯ２地中貯留に対するリスクアセスメント取り組みの現状

In this paper, the authors review the latest situation of risk assessment research efforts on to Carbon Dioxide Geological Storage (geological CCS) technology. After publication of the special report on geological CCS (2005) with sections about risk assessment, significant progresses have been achieved in risk assessment as technological evaluation of geological CCS as one of likely greenhouse gas discharge reduction measure. Those efforts produced permission scheme or safety guideline for geological CCS in some countries. On the other hand, as regard with research and development for precise risk assessment and management of CO2 Geological Storage, it is on the halfway of establishing methodologies. To establish quantitative assessment methodology for rational and reasonable risk governance of this field, the following additional research and development efforts are still urgently required: hazard data collection, data preparation for evaluation about surface facilities and surface local environment, and establishing methodology for uncertainty treatment of geological formation.

Sorption of carbon dioxide, methane and nitrogen in dry coals at high pressure and moderate temperature

In view of the growing interest in enhanced coal bed methane recovery, a technique under investigation as a possible approach to the geological storage of carbon dioxide in a CO 2 capture and storage system, we have studied experimentally the interaction of different gases in contact with coal at pressure and temperature levels typical of coal seams. In particular, samples of coals of different geological origin and different characteristics have been considered. A gravimetric method using a magnetic suspension balance has been applied to measure the excess sorption isotherms of CO 2 , CH 4 and N 2 between 33 and 60 °C and up to 200 bar. The obtained sorption isotherms on two coal samples from Australia are consistent with the data measured in a laboratory there. Maximum sorption capacities of the coals investigated lie within the range of 5–14% weight per unit mass of coal for CO 2 and of 1–3% for CH 4 and N 2 . Moreover, for all gases sorption capacity has been found to decrease with increasing vitrinite reflectance. A Langmuir-like model has been applied to the sorption data, by fitting the isotherm parameters to the experimental values. The results confirm that this equation is a valuable option to describe gas sorption on coal. Moreover, it is shown that the two mechanisms involved in the gas uptake process, namely adsorption and absorption, can be separated only if independent experimental data about coal swelling are available. The proposed model is compared to another isotherm equation presented in the literature, namely a modified Dubinin–Radushkevich adsorption isotherm, which uses a linear law to describe absorption.

Design considerations for financing a national trust to advance the deployment of geologic CO 2 storage and motivate best practices

This paper explores how the widely held public policy view of the evolution of the risk profile associated with geologic carbon dioxide (CO 2) storage profoundly influences the public policy dialogue about how to best address the long-term risk profile for geologic storage. Evidence emerging from research and pilot scale field demonstrations of CO 2 storage demonstrates that, with proper site characterization and sound operating practices, retention of stored CO 2 will increase with time thus invalidating the premise of an ever growing risk. The authors focus on key issues of fit, interplay, and scalability associated with the ability of a trust fund funded by a hypothetical $1 per tonCO 2 tipping fee for each ton of CO 2 stored in the United States under WRE450 and WRE550 climate policies to manage such risks in an economically efficient and environmentally effective manner. The authors conclude there is no intrinsic value – in terms of risk management or risk reduction – in creating a trust fund predicated solely on collecting a universally applied tipping fee that does not take into account site-specific risk profiles. If left to grow unchecked, a trust fund that is predicated on a constant stream of payments unrelated to each contributing site's risk profile could result in the accumulation of hundreds of billions to more than a trillion dollars contributing to significant opportunity cost of capital. Further, rather than mitigating the financial consequences of long-term CCS risks, this analysis suggests a blanket $1 per tonCO 2 tipping fee, if combined with a concomitant limitation of liability may increase the probability and frequency of long-term risk by eliminating financial incentives for sound operating behavior and site selection criteria—contribute to moral hazard. At a minimum, effective use of a trust fund requires: (1) strong oversight regarding site selection and fund management, and (2) a clear process by which the fund is periodically valued and funds collected are mapped to the risk profile of the pool of covered CCS sites. Without appropriate checks and balances, there is no a priori reason to believe that the amount of funds held in trust will map to the actual amount of funds needed to address long-term care expenses and delimited compensatory damages. For this reason, the authors conclude that financing a trust fund or other risk management instrument should be based on a site delimited estimate of potential future expected financial consequences rather than on the random adoption of a fixed funding stream, e.g., a blanket $1 per ton, because it “sounds” reasonable.

Analysis of CO2 Endpoint Relative Permeability and Injectivity by Change in Pressure, Temperature, and Phase in Saline Aquifer

Carbon dioxide capture and geological storage are considered to be imperative practical means for reducing greenhouse gas emissions into the atmosphere. Among geological formations for carbon dioxide capture and geological storage, deep saline aquifer is tracked as a key site due to its huge potential and common occurrence when compared to oil and gas reservoirs. But, the two-phase behavior of CO2 accompanied with water formation under conditions equivalent to geological storage are mostly unknown. In this study, relative permeability experiments have been conducted to measure the end-point relative permeability of CO2 and investigations have been carried out to calculate injectivity using the relative permeability. In CO2 and water system, the injectivity is the function of the CO2 endpoint relative permeability. An experimental apparatus for CO2-water relative permeability was designed and experiments were carried out under six different temperatures varying from 70°F to 120°F, while the cell pressure was varied from 500 to 1,300 psi for every respective temperature. From the results, it was evident that, in general, the endpoint relative permeability of carbon dioxide increases with decrease in viscosity ratio, while the endpoint relative permeability in the transition region between gas and supercritical decreases even with decreasing viscosity ratio. Also, based on the sensitivity studies carried out by varying pressure and temperature, it was experimentally confirmed that porous and permeable aquifers at a minimum depth of more than 800 m are the most appropriate storage sites.

CO2 Storage: Managing the Risk Associated With Well Leakage Over Long Time Scales

Summary One of the major challenges associated with the geological storage of carbon dioxide (CO2) is the performance of the confining system over long time scales. In particular, the occurrence of CO2 leakage through existing wells could not only defeat the purpose of storage, but also badly affect human health or the environment. Cement degradation and casing corrosion in injection, production, or abandoned wells can create preferential channels over time, allowing the migration of CO2 from the reservoir to shallower formations (e.g. aquifers), and/or to the surface. In this paper, a risk-based approach is proposed for well-integrity and confinement-performance management. The approach, based on Performance and Risk Management methodology (P&R™), serves as a decision-support tool. The major steps in this methodology are identifying the system and sources of degradation through characterization and system analysis; quantifying their criticality through modeling, in terms of probability and severity; and establishing a risk-mitigation plan. This methodology is based on experience in material aging and risk assessment of complex systems, such as nuclear structures where probabilistic simulations are performed. It accounts for all stakes involved in well-integrity management and enables the full integration of uncertainties as part of risk estimation. The methodology presented here greatly improves common approaches based on "features, events, and processes" because it quantifies risk levels. It provides useful and reliable tools to support decisions for well-integrity-management strategies or emergency plans. To that purpose, mitigation actions such as characterization/inspection, remediation (workover), design improvement, or monitoring are valued on the basis of a cost/benefit ratio. Moreover, updating the risk assessment with incoming data allows for an evolving vision of risk levels to optimize interventions over time. This approach has been applied successfully, leading to recommendations for safer and more-efficient design, maintenance, and monitoring strategies.

Hydrogeochemical modeling of a thermal system and lessons learned for CO 2 geologic storage

Geological storage of carbon dioxide is presently considered to be one of the main strategies to mitigate the impact of the emissions of this gas on global warming. Among the various alternatives considered for CO 2 geological storage, one of the main geological candidates for hosting injected CO 2 in the long term are deep porous reservoir rock formations saturated with brackish or saline solutions. Although valuable information on the expected hydrogeochemical processes involved in the CO 2 storage in such deep saline aquifers can be obtained in laboratory or modeling studies, the only direct source of information about the long-term behavior of geological storages for CO 2 in deep aquifers is natural analogues. In this work, a classical and simple geochemical methodology is successfully applied to the study of the features and hydrogeochemical processes determining the evolution of a Spanish thermal system (the Alhama–Jaraba complex), which can be considered as a natural analogue for deep geological CO 2 storage in carbonate rocks. The geology, structure, depth and hydrogeochemistry of the Alhama–Jaraba thermal system are very similar to the expected features of a potential CO 2 reservoir in carbonate materials. The processes determining the hydrogeochemical evolution in the Alhama–Jaraba thermal system have been successfully identified and quantified with the assistance of ion–ion plots, speciation–solubility calculations and mass-balance calculations. Furthermore, the feasibility of the proposed conceptual hydrogeochemical model for this system has been verified by using reaction-path calculations. Mass-balance calculation results have indicated that the observed hydrogeochemical evolution between springs is mainly due to halite dissolution and dedolomitization triggered by gypsum or anhydrite dissolution. CO 2(g) mass transfer has been estimated to be negligible, which suggests that the main processes responsible for the variation in the TIC and the CO 2(g) pressure during deep circulation are dissolution and precipitation reactions for carbonate minerals. All the processes identified in the Alhama–Jaraba thermal system are relevant for the long-term evolution of a deep CO 2 storage site hosted by carbonate rocks. As shown in this study, the application of classical geochemical tools provides an excellent starting point for understanding the behavior of prospective storage systems. Moreover, the existence of dedolomitization is very relevant for the hydraulic properties of carbonate aquifers potentially used for CO 2 geological storage because of the effects on porosity and, therefore, permeability during the long-term evolution of such systems. Furthermore, dedolomitization may represent a mechanism of mineral trapping for CO 2 sequestration under certain conditions.

Practical Modeling Approaches for Geological Storage of Carbon Dioxide

The relentless increase of anthropogenic carbon dioxide emissions and the associated concerns about climate change have motivated new ideas about carbon-constrained energy production. One technological approach to control carbon dioxide emissions is carbon capture and storage, or CCS. The underlying idea of CCS is to capture the carbon before it emitted to the atmosphere and store it somewhere other than the atmosphere. Currently, the most attractive option for large-scale storage is in deep geological formations, including deep saline aquifers. Many physical and chemical processes can affect the fate of the injected CO2, with the overall mathematical description of the complete system becoming very complex. Our approach to the problem has been to reduce complexity as much as possible, so that we can focus on the few truly important questions about the injected CO2, most of which involve leakage out of the injection formation. Toward this end, we have established a set of simplifying assumptions that allow us to derive simplified models, which can be solved numerically or, for the most simplified cases, analytically. These simplified models allow calculation of solutions to large-scale injection and leakage problems in ways that traditional multicomponent multiphase simulators cannot. Such simplified models provide important tools for system analysis, screening calculations, and overall risk-assessment calculations. We believe this is a practical and important approach to model geological storage of carbon dioxide. It also serves as an example of how complex systems can be simplified while retaining the essential physics of the problem.

The New Directive on the Geological Storage of Carbon Dioxide

Carbon capture and storage (CCS) is a controversial response to climate change, described variously as a ‘magic bullet’;¹ ‘an uncomfortable but necessary option’;² ‘an expensive distraction’;³ and a ‘false hope’.⁴ The Directive on the geological storage of carbon dioxide (CO2)⁵ provides a legal framework for the regulation of CCS. CCS is the process of removing CO2 from the emissions of industrial processes, injecting and storing it permanently underground, where it is prevented from entering into the atmosphere and thus contributing to climate change. While the climate change imperative seems to have provided significant impetus for expedited negotiation and adoption of the Directive,⁶ CCS technology is of course as much about energy security and the continued use of fossil fuels.⁷ In response to policy options which would favour enhanced investment in renewables and energyefficie ncy over the continued use of coal, the Directive notably describes CCS as ‘a bridging technology’ which ‘should not serve as an incentive to increase the share of fossil fuel power plants’.⁸

Numerical Modeling of Pressure and Temperature Profiles Including Phase Transitions in Carbon Dioxide Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115946, "Numerical Modeling of Pressure and Temperature Profiles Including Phase Transitions in Carbon Dioxide Wells," by Lincoln Paterson, SPE, CO2CRC, CSIRO; Meng Lu, SPE, and Luke D. Connell, SPE, CSIRO; and Jonathan Ennis-King, SPE, CO2CRC, CSIRO, prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed. Geological storage of carbon dioxide (CO2) usually is at conditions above the critical temperature and pressure; therefore, the CO2 will exist as a single dense phase. However, conditions in the upper part of a CO2 well with surface temperatures below the critical point of 31°C can lead to boiling and condensation in the well. The consequences of this are most apparent when the flow rate changes. Density profiles have been calculated for wells experiencing different thermal conditions to determine how bottomhole pressures are related to wellhead pressures. Introduction CO2-injection wells are used in enhanced oil recovery (EOR). CO2-production wells, from underground natural accumulations, provide a source of CO2 for EOR and other industrial uses. Interest in CO2 wells has intensified for geological storage as a means of reducing atmospheric greenhouse gases. Accurate determination of downhole pressures is important if pressure is used to monitor the performance of a geological-storage reservoir. Reliable knowledge of bottomhole pressure helps prevent injection above pressures that can damage the formation. While bottomhole pressure can be measured with gauges, it is possible that, over a long period of time, downhole gauges may fail. Hence, calculating downhole pressure from wellhead pressure is desired. CO2 has a critical pressure of 7.38 MPa and critical temperature of 31.0°C, so if the fluid is near the usual surface temperatures, conditions in the upper part of a well can cross the saturation line of CO2, with boiling and condensation in the well if fluid pressures are in the vicinity of the critical pressure. Also, near the saturation line of CO2, fluid properties display severely nonlinear behavior, challenging numerical simulation. This phase-change issue usually is not of concern during injection of CO2 for EOR because EOR normally involves continuous columns of liquid to the surface with the reservoir pressures required for minimum miscibility. Conditions for phase change are more likely in circumstances not involving EOR, including CO2 production from depleted CO2 reservoirs, CO2 injection into pressure-depleted gas reservoirs, and CO2 storage at depths less than 2000 m. The mathematical treatment of well-bore flow has been described extensively. The full-length paper details the interpretation of flow by use of numerical methods. In the rock surrounding the well, phase change accompanying vertical migration of CO2 during hypothetical leakage has been studied. Leakage usually involves smaller flow rates and closer thermal coupling to the surrounding rock compared with wellbore flow.

Geological Storage of Carbon Dioxide

Book Review| May 01, 2009 Geological Storage of Carbon Dioxide Richard E. Jackson Richard E. Jackson 1INTERA Engineering Ltd., 11 Venus Crescent, Heidelberg, Ontario, N0B 1Y0 Canada Search for other works by this author on: GSW Google Scholar Environmental & Engineering Geoscience (2009) 15 (2): 115–116. https://doi.org/10.2113/gseegeosci.15.2.115 Article history first online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Tools Icon Tools Get Permissions Search Site Citation Richard E. Jackson; Geological Storage of Carbon Dioxide. Environmental & Engineering Geoscience 2009;; 15 (2): 115–116. doi: https://doi.org/10.2113/gseegeosci.15.2.115 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyEnvironmental & Engineering Geoscience Search Advanced Search In the 8 years since these papers were first presented at the 2001 meeting of the European Union of Geoscientists, a multitude of articles on deep CO2 storage in aquifers or petroleum reservoirs has appeared in journals such as Environmental Science & Technology, Energy Conversion & Management, and the publications of the Society of Petroleum Engineers. In that time and with U.S. Department of Energy support, the principal coal-mining and coal-burning states have formed seven Regional Carbon Sequestration Partnerships plus the Midwest Geological Sequestration Consortium. This latter Consortium recently began drilling an approximately 8,000-foot-deep injection well at... You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

A technical basis for carbon dioxide storage

Abstract This paper is the synopsis of a larger work completed under the auspices of the CO 2 Capture Project, an international effort funded by eight of the world’s leading energy companies. It seeks to explain the rationale for the geological storage of carbon dioxide (CO 2 ) based on insights from the practical experience of the oil and gas industry. It considers the key technical applications that will make storage possible, and the subsurface management processes that will provide confidence to all stakeholders that storage is effective. Four broad areas are described including, the selection and characterization of sites for CO 2 storage; issues of well integrity and well construction; the requirements of monitoring programs for appropriate data collection and risk management. Finally, issues arising from storage operations and the eventual closure and decommissioning of CO 2 storage sites are addressed.

Geological storage of carbon dioxide: Current status

This article was submitted without an abstract, please refer to the full-text PDF file.

Modelling the fate of carbon dioxide in the near-surface environment at the Latera natural analogue site

Abstract Latera is a volcanic area north of Rome where deep, naturally-produced carbon dioxide migrates to the surface and is released to the atmosphere. The region provides an environment in which many processes relevant to the geological storage of carbon dioxide can be studied. This paper describes system-level modelling studies using Quintessa’s QPAC–CO2 code, which includes a novel soil–plant model that represents both fertilization and toxicity effects from elevated carbon dioxide concentrations. Good comparisons have been obtained between model calculations of surface venting patterns, soil gas concentrations and plant responses, giving confidence that the key features of the system are well understood.

Geological storage of carbon dioxide: Current status

Geological storage of carbon dioxide: Current status

Assessing capacity for geological storage of carbon dioxide in central—east group of countries (EU GeoCapacity project)

Abstract In the frame of the EU - based GeoCapacity project 1 , the capacity for CO 2 geological storage is being estimated for 23 countries of Europe. This project supplements the FP5 GESTCO project covering the whole area of E urope and the countries under study have been classified in three (3) groups for easy of work. The Central - East group of countries comprises Greece (update of GESTCO estimates), Albania, FYROM, Bulgaria, Romania and Hungary. The paper give s an overview o f the work and results of which - since January 2006 - has been focussing on mapping large CO 2 point sources, infrastructure and potential for geological storage in this group of European countries. From up today results it is evident that the annual emis sions, the type of sinks, suitable for CO 2 storage, and the estimated potential varies largely between the countries of the group. The annual CO 2 emissions from large point sources (> 0. 1 Mt) were recorded and in decreasing order are as follows per co untry: Romania 80 Mt, Greece 69 Mt, Bulgaria 52 Mt, Hungary 26 Mt, FYROM 4 Mt, Albania 0,3 Mt. The type of suitable sinks for CO 2 storage and the estimated potential varies significantly. The largest potential has been estimated in saline and fresh aquifer s followed by hydrocarbon reservoirs and for some countries in coal seams. The storage capacity has been estimated by using the standard methodology developed for the project. The highest capacity occurs in Hungary in onshore aquifers and hydrocarbon and coal fields where the quality of storage is poor. Bulgaria has a high potential in aquifers, low in hydrocarbon fields and very low in coal seams. The same is true for Greece. Romania has a very high storage potential in aquifers and high in hydrocarbon fi elds (both offshore and onshore). FYROM has a high capacity of CO 2 storage in one aquifer which can host the emissions (low in quantity) for many decades (under the present rate). Finally Albania presents a low potential in hydrocarbon fields and aquifers but a big one in the salt domes. Given the very low quantity of Albania’s annual CO 2 emissions, this limited potential can accommodate the present emissions for many decades. For each of the six countries of the group, 1 -2 case studie s are under compilation and they will be studied under some scenarios of source - sink matching, using the Decision Support System (D.S.S.) developed for the project.

Assessing European capacity for geological storage of carbon dioxide–the EU GeoCapacity project

The focus of the GeoCapacity project is GIS mapping of CO2 point sources, infrastructure and geological storage in Europe. The main objective is to assess the European capacity for geological storage of CO2 in deep saline aquifers, oil and gas structures and coal beds. Other priorities are further development of methods for capacity assessment, economic modelling and site selection as well as international cooperation, especially with China. The results of GeoCapacity will include 25 countries and comprises most European sedimentary basins suitable for geological storage of CO2. © 2009 Elsevier Ltd. All rights reserved.

Assessment of the potential for geological storage of carbon dioxide in Ireland and Northern Ireland

The project used a multi-disciplinary approach to assess the potential for carbon capture and storage (CCS) offshore and onshore Ireland and Northern Ireland. The project work flow has used internationally recognised methodology to produce an integrated capture to storage road map for the island of Ireland. Using a basin-by-by basin approach, each sedimentary basin was individually assessed for carbon dioxide (CO2) storage potential in hydrocarbon fields and saline aquifers. CSLF methodology was applied to calculate storage capacity for the identified sites; each potential storage site was categorised according to the CSLF techno-economic resource pyramid [S. Bachu, D. Bonijoly, J. Bradshaw, R. Burruss, N.P. Christensen, S. Holloway, O.M. Mathiassen, Estimation of CO2 Storage Capacity in Geological Media, Phase 2. Prepared for the Task Force on CO2 Storage Capacity Estimation for the Technical Group of the Carbon Sequestration Leadership Forum, 2007]. Identification and characterisation of point sources allowed hub scenarios to be developed between the major CO2 point source emissions and the most promising geological storage sites. This allowed potential pipeline routes to be identified and engineering specification and costs to be addressed as well as consideration of planning, public safety and environmental issues. A range of capture transport and storage options were produced and subjected to rigorous economic assessment. The major hubs identified are as follows: Moneypoint (Co. Clare) - Kinsale Head Gas Field, North Celtic Sea Kilroot (Co. Antrim) - Closed structures in the Portpatrick Basin Cork - Kinsale Head Gas Field, North Celtic Sea

Training carbon management engineers: why new educational capacity is the single biggest hurdle for geologic CO2 storage

Abstract Implementing geologic storage of carbon dioxide at a scale large enough to make a difference will require an industry of magnitude comparable to the current oil and gas industry (Bryant [1]; Orr [2]). Such an enterprise will require substantial human capital, but recognition of this need has been largely missing from discussions of GHG mitigation. To design, build, implement, optimize, troubleshoot, monitor and regulate large-scale carbon dioxide storage projects will require subsurface engineers. The same technologies that apply to hydrocarbon production apply to the subsurface storage of carbon dioxide. Thus one might naturally expect to hire petroleum engineering (PE) graduates to staff a carbon storage industry. We argue that it is unrealistic to depend on PE graduates to staff the carbon storage industry, for three reasons: (i) continued large demand for hydrocarbons is unlikely to abate; (ii) a demographic gap in the oil and gas industry will continue to place an extraordinary premium on new graduates; and (iii) existing PE departments in the US and abroad are already operating at or above capacity. In short, there are neither classrooms nor faculty sufficient to educate enough petroleum engineers for the petroleum industry. Even if there were, it would be difficult for an emerging carbon storage industry to compete for graduates with oil and gas companies. We advocate that the solution to this manpower problem is building new educational infrastructure. We propose a prototype program based on an existing accredited multidisciplinary degree program at The University of Texas at Austin, known as Geosystems Engineering and Hydrogeology. Offered jointly by the Petroleum and Geosystems Engineering Department and the Department of Geological Sciences, this program combines the fundamentals of petroleum engineering with the subsurface architecture emphasis of geology and the environmental perspective of hydrogeology. The latter is salient given the priority of protecting groundwater resources during geologic storage. With modest redesign of the curriculum but with substantial expansion of classrooms, laboratories and faculty, we argue that the program would be able to graduate significant numbers of “carbon management engineers” within six years. The problem of timing is particularly difficult. The lead time to develop such a program is long, even when starting from an existing degree program. A geologic storage industry will not begin until a regulatory framework and some form of carbon market or price are established. Ensuring that the carbon management industry is not starved of talent will thus require a rare combination of shared vision amongst university administrators, government agencies and industry.

Assessing issues of financing a CO2 transportation pipeline infrastructure

Abstract For carbon dioxide capture and geologic storage to be deployed commercially and in a widespread manner will require well thought out approaches for transporting the CO 2 in a pipeline system from the capture facility to the injection site. Establishing a widespread CO 2 transportation infrastructure will require strategic long-term planning, taking into account the potential magnitude of future deployment scenarios for CCS, up to a scale of infrastructure that could be comparable to the scale of oil & gas infrastructure. This paper outlines the results of a study, commissioned by the CO 2 Capture Project (CCP) and completed by Environmental Resources Management (ERM) that evaluated the benefits and risks of two approaches to developing CO 2 pipeline systems. The two basic approaches are described in the paper as: 1. On a point-to-point basis, which matches a specific source to a specific storage location; or 2. Via the development of pipeline networks, including backbone pipeline systems, which allow for common carriage of CO 2 from multiple sources to multiple sinks. An integrated approach to pipeline infrastructure approach offers the lowest average cost on a per ton basis for operators over the life of the projects if sufficient capacity utilization is achieved relatively early in the life of the pipeline. Integrated pipelines also reduce the barriers to entry and are more likely to lead to faster development and deployment of CCS. Without incentives to encourage the development of optimized networks project developers are likely to build point to point pipelines because they offer lower costs for the first movers and do not have the same capacity utilization risk.