Public risk perspectives on the geologic storage of carbon dioxide

Carbon Dioxide Capture and Storage (CCS) technology has the potential to enable large reductions in global greenhouse gas emissions, but one of the unanswered questions about CCS is to what extent it will be accepted by the public. To provide insight regarding risk perception as an important component that will influence the public acceptance of CCS, this study discusses different notions of risk and their varying uses by the public, who generally use a social constructivist risk perspective, and risk experts, who generally use a realist perspective. Previous studies discussing the public acceptance of CCS have relied on survey response data and/or focus groups. This study instead uses the psychometric theory of public risk perception to postulate how the public is likely to respond to efforts to use geologic storage of CO₂, a component of the CCS architecture. Additionally this paper proposes further actions that could favorably impact the public's perception of risk from geologic storage projects. Through the psychometric analysis this study concludes that the risks of geologic storage are likely to eventually be considered no worse than existing fossil fuel energy technologies. However, since geologic storage of CO₂ is a new technology with little operational experience, additional field tests and a demonstrated ability to mitigate problems should they arise will be necessary to improve the public's perception of risk from CCS technologies.     

Economic evaluation of the geological storage of CO2 considering the scale of economy

CO₂ capture and storage (CCS) technology is expected to play an important role in the efforts directed toward long-term CO₂ emission reduction. This paper analyzes the cost of the geological storage of CO₂ in Japan in order to consider future research, development and deployment (RD&D); these would be based on the information of the obtained cost structure. According to the analysis results, the costs, particularly those of the transportation by pipeline and of CO₂ injection, strongly depend on the scale of the facilities. Therefore, the distance of the transportation of CO₂ should be minimized in the case of small-scale storage, particularly in Japan. In addition, the potential injection rate per well is another key factor for the injection cost. Based on the analyzed cost, the injection cost of the geological storage of CO₂ in Japan for individual storage sites is estimated, and the cost–potential curve is obtained. A mixed-integer programming model has been developed to take into account these characteristics of the CCS technology and its adverse effects arising from the scale of economy with regard to the transportation and injection cost for the geological storage of CO₂. The model is designed to evaluate CCS and other CO₂ mitigation technologies in the energy systems of Japan. With all these adverse effects due to the scale of economy, the geological storage of CO₂ will be one of the important options for CO₂ emission reduction in Japan.     

Regulatory challenges and managing public perception in planning a geological storage pilot project in Australia

The implementation of geological storage of CO₂ requires not only further research and development but also the demonstration of carbon dioxide capture and storage (CCS) technology as a viable option. A pilot program is an important first step towards building industry and community confidence in the application of CCS. The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Australia's leading research organisation in CCS, has initiated a comprehensive research and demonstration program in the Otway Basin in South-West Victoria. As the first project of its kind in Australia, the Otway Basin Pilot Project (OBPP) has faced a number of regulatory and organisational challenges while having to concurrently address public perception. The Otway Basin site with its natural CO₂ accumulations and many depleted natural gas fields offers an appropriate CO₂ storage site to test scientific and regulatory concepts and evaluate public response through social research. The project aims to show that CO₂ can be safely captured, transported and stored deep underground under local conditions, and also monitored and verified. Planning has been ongoing for over a year, baseline studies are underway and the project is targeted to start injection in 2007.     

Lessons learned from natural and industrial analogues for storage of carbon dioxide

The deployment of CCS (carbon capture and storage) at industrial scale implies the development of effective monitoring tools. Noble gases are tracers usually proposed to track CO₂. This methodology, combined with the geochemistry of carbon isotopes, has been tested on available analogues.At first, gases from natural analogues were sampled in the Colorado Plateau and in the French carbogaseous provinces, in both well-confined and leaking-sites. Second, we performed a 2-years tracing experience on an underground natural gas storage, sampling gas each month during injection and withdrawal periods.In natural analogues, the geochemical fingerprints are dependent on the containment criterion and on the geological context, giving tools to detect a leakage of deep-CO₂ toward surface. This study also provides information on the origin of CO₂, as well as residence time of fluids within the crust and clues on the physico-chemical processes occurring during the geological story.The study on the industrial analogue demonstrates the feasibility of using noble gases as tracers of CO₂. Withdrawn gases follow geochemical trends coherent with mixing processes between injected gas end-members. Physico-chemical processes revealed by the tracing occur at transient state.These two complementary studies proved the interest of geochemical monitoring to survey the CO₂ behaviour, and gave information on its use.     

Coalbed methane reservoir data and simulator parameter uncertainty modelling for CO2 storage performance assessment

Laboratory studies and a number of field pilots have demonstrated that CO₂ injection into coal seams has the potential to enhance coalbed methane (CBM) recovery with the added advantage that most of the injected CO₂ can be stored permanently in coal. The concept of storing CO₂ in geologic formations as a safe and effective greenhouse gas mitigation option requires public and regulatory acceptance. In this context it is important to develop a good understanding of the reservoir performance, uncertainties and the risks that are associated with geological storage. The paper presented refers to the sources of uncertainty involved in CO₂ storage performance assessment in coalbed methane reservoirs and demonstrates their significance using extensive digital well log data representing the Manville coals in Alberta, Canada. The spatial variability of the reservoir properties was captured through geostatistical analysis, and sequential Gaussian simulations of these provided multiple realisations for the reservoir simulator inputs. A number of CO₂ injection scenarios with variable matrix swelling coefficients were evaluated using a 2D reservoir model and spatially distributed realisations of total net thickness and permeability.     

The acceptability of CO2 capture and storage (CCS) in Europe: An assessment of the key determining factors: Part 1. Scientific,technical and economic dimensions

The ACCSEPT project, which ran from January 2006 to December 2007, identified and analysed the main factors which have been influencing the emergence of CO₂ capture and geological storage (CCS) within the European Union (EU). The key clusters of factors concern science and technology, law and regulation, economics, and social acceptance. These factors have been analysed through interviews, a large-scale questionnaire conducted in 2006, and discussions in two stakeholder workshops (2006 and 2007). In Part I of this paper, we aim to distil the key messages and findings with regards to scientific, technical, legal and economic issues. There are no compelling scientific, technical, legal, or economic reasons why CCS could not be widely deployed in the forthcoming decades as part of a package of climate change mitigation options. In order to facilitate this deployment, governments at both the EU and Member State levels have an important role to play, in particular in establishing a robust and transparent legal framework (e.g. governing long-term environmental liability) and a strong policy framework providing sufficient and long-term incentives for CCS and CO₂ transportation networks.     

“The Schweinrich structure”, a potential site for industrial scale CO2 storage and a test case for safety assessment in Germany

The identification of risks associated with the geological storage of CO₂ requires methods that can analyse and assess potential safety hazards. This paper evaluates how performance assessment can be used as a method for assessing the impact of CO₂ storage on health, safety and the environment (HSE) with particular respect to potential future aquifer storage in the anticlinal structure Schweinrich in Germany. The performance assessment was conducted under the CO2STORE European Fifth Framework project as one of the four cases on the aquifer storage of CO₂. It is known as the Schwarze Pumpe case study.Being a case study, it is restrictive from a feasibility study point of view—i.e., the extended identification of the key safety factors where an actual CO₂ storage project would be considered for the Schweinrich structure. The study is based on data currently available, gathered in prior surveys, and on the use of simplified models, with CO₂ leakage levels from natural analogues being the evaluation criteria. While the results should be interpreted as provisional, they point out clearly which additional data should be gathered in relation to the long-term storage performance in the event that the site warrants further investigation.     

Lay perceptions of carbon capture and storage technology

The extent of social acceptance of carbon capture and storage (CCS) is likely to significantly influence the sustainable development of CO₂ storage projects. Acceptance of CCS by the key stakeholders (policy makers, the general public, the media and the local community), linked to specific projects, as well as how the technology is communicated about and perceived by the public, have become matters of interest for the social sciences. This article reports on an investigation of the public perception of CCS technology in Spain. Individuals’ views on CCS are analysed through focus groups with lay citizens using “stimulus materials”. As the analysis shows, lay views of CCS differ significantly from the views of decision-makers and experts. Public concerns and reactions to CCS technology and potential projects, as well as the degree of consensus on its acceptance or rejection are detailed. Implications for the future use of CCS are discussed.     

Simultaneous CO2 injection and water production to optimise aquifer storage capacity

The estimates for geological CO₂ storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO₂ that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential.In static capacity estimates, where the maximum stored amount of CO₂ is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO₂ is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO₂. The EU directive on geological CO₂ storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO₂ that can be injected.One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO₂ injection wells. This paper discusses results from simulations of CO₂ injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO₂ shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO₂ over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer.Several design options for the injection operations are investigated: Injection of CO₂ without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed.     

An empirical study on the public perception and acceptance of hydrogen energy in Taiwan

In this study, we extract factors by using factor analysis and then adopt them in a regression analysis to investigate the public perception and acceptance of hydrogen energy in Taiwan. Six reliable factors were extracted from the exploratory factor analysis of 29 5-point Likert-type items. Our regression results show that the public perception of hydrogen energy as a green energy, public belief in domestic hydrogen industries being able to conform to international safety standards, and public perception of the cost advantage of hydrogen gas over petroleum have significantly positive effects on support for the development of hydrogen energy in Taiwan. While people have a high level of concern about the safety of hydrogen and its associated technologies, the unsafe perceptions of hydrogen and its associated technologies have no significant effects on their support. In particular, public belief in domestic hydrogen industries being able to conform to international safety standards is a powerful factor that enhances support for hydrogen energy development.     

CO2 storage capacity estimation: Methodology and gaps

Implementation of CO₂ capture and geological storage (CCGS) technology at the scale needed to achieve a significant and meaningful reduction in CO₂ emissions requires knowledge of the available CO₂ storage capacity. CO₂ storage capacity assessments may be conducted at various scales—in decreasing order of size and increasing order of resolution: country, basin, regional, local and site-specific. Estimation of the CO₂ storage capacity in depleted oil and gas reservoirs is straightforward and is based on recoverable reserves, reservoir properties and in situ CO₂ characteristics. In the case of CO₂-EOR, the CO₂ storage capacity can be roughly evaluated on the basis of worldwide field experience or more accurately through numerical simulations. Determination of the theoretical CO₂ storage capacity in coal beds is based on coal thickness and CO₂ adsorption isotherms, and recovery and completion factors. Evaluation of the CO₂ storage capacity in deep saline aquifers is very complex because four trapping mechanisms that act at different rates are involved and, at times, all mechanisms may be operating simultaneously. The level of detail and resolution required in the data make reliable and accurate estimation of CO₂ storage capacity in deep saline aquifers practical only at the local and site-specific scales. This paper follows a previous one on issues and development of standards for CO₂ storage capacity estimation, and provides a clear set of definitions and methodologies for the assessment of CO₂ storage capacity in geological media. Notwithstanding the defined methodologies suggested for estimating CO₂ storage capacity, major challenges lie ahead because of lack of data, particularly for coal beds and deep saline aquifers, lack of knowledge about the coefficients that reduce storage capacity from theoretical to effective and to practical, and lack of knowledge about the interplay between various trapping mechanisms at work in deep saline aquifers.     

Intermediate storage of carbon dioxide in geological formations: A technical perspective

Enhanced oil recovery (EOR) through CO₂ flooding has been practiced on a commercial basis for the last 35 years and continues today at several sites, currently injecting in total over 30 million tons of CO₂ annually. This practice is currently exclusively for economic gain, but can potentially contribute to the reduction of emissions of greenhouse gases provided it is implemented on a large scale. Optimal operations in distributing CO₂ to CO₂-EOR or enhanced gas recovery (EGR) projects (referred to here collectively as CO₂-EHR) on a large scale and long time span imply that intermediate storage of CO₂ in geological formations may be a key component. Intermediate storage is defined as the storage of CO₂ in geological media for a limited time span such that the CO₂ can be sufficiently reproduced for later use in CO₂-EHR. This paper investigates the technical aspects, key individual parameters and possibilities of intermediate storage of CO₂ in geological formations aiming at large scale implementation of carbon dioxide capture and storage (CCS) for deep emission reduction. The main parameters are thus the depth of injection and density, CO₂ flow and transport processes, storage mechanisms, reservoir heterogeneity, the presence of impurities, the type of the reservoirs and the duration of intermediate storage. Structural traps with no flow of formation water combined with proper injection planning such as gas-phase injection favour intermediate storage in deep saline aquifers. In depleted oil and gas fields, high permeability, homogeneous reservoirs with structural traps (e.g. anticlinal structures) are good candidates for intermediate CO₂ storage. Intuitively, depleted natural gas reservoirs can be potential candidates for intermediate storage of carbon dioxide due to similarity in storage characteristics.     

Petrophysical analysis to investigate the effects of carbon dioxide storage in a subsurface saline aquifer at Ketzin, Germany (CO2SINK)

To test the injection behaviour of CO₂ into brine-saturated rock and to evaluate the dependence of geophysical properties on CO₂ injection, flow and exposure experiments with brine and CO₂ were performed on sandstone samples of the Stuttgart Formation representing potential reservoir rocks for CO₂ storage. The sandstone samples studied are generally fine-grained with porosities between 17 and 32% and permeabilities between 1 and 100 mD.Additional batch experiments were performed to predict the long-term behaviour of geological CO₂ storage. Reservoir rock samples were exposed over a period of several months to CO₂-saturated reservoir fluid in high-pressure vessels under in situ temperature and pressure conditions. Petrophysical parameters, porosity and the pore radius distribution were investigated before and after the experiments by NMR (Nuclear Magnetic Resonance) relaxation and mercury injection. Most of the NMR measurements of the tested samples showed a slight increase of porosity and a higher proportion of large pores.     

Pipeline design for a least-cost router application for CO2 transport in the CO2 sequestration cycle

CO₂ capture and geological storage (CCS) is considered as a viable option to mitigate greenhouse gas emissions during the transition phase towards the use of clean and renewable energy. This paper concentrates on the transport of CO₂ between source (CO₂ capture at plants) and sink (geological storage reservoirs). In the cost estimation of CO₂ transport, the pipeline diameter plays an important role. In this respect, the paper reviews equations that were used in several reports on CO₂ pipeline transport. As some parameters are not taken into account in these equations, alternative formulas are proposed which calculate the proper inner diameter size based on flow rate, pressure drop per unit length, CO₂ density, CO₂ viscosity, pipeline material roughness and topographic height differences (the Darcy–Weisbach solution) and, in addition, on the amount and type of bends (the Manning solution). Comparison between calculated diameters using the reviewed and the proposed equations demonstrate the important influence of elevation difference (which is not considered in the reviewed equations) and pipeline material roughness-related factor on the calculated diameter. Concerning the latter, it is suggested that a Darcy–Weisbach roughness height of 0.045 mm better corresponds to a Manning factor of 0.009 than higher Manning values previously proposed in literature. Comparison with the actual diameter of the Weyburn pipeline confirms the accuracy of the proposed equations. Comparison with other existing CO₂ pipelines (without pressure information) indicate that the pipelines are designed for lower pressure gradients than 25 Pa/m or for (future) higher flow rates. The proposed Manning equation is implemented in an economic least-cost route planner in order to obtain the best economic solution for pipeline trajectory and corresponding diameter.     

CO2 storage capacity estimation: Issues and development of standards

Associated with the endeavours of geoscientists to pursue the promise that geological storage of CO₂ has of potentially making deep cuts into greenhouse gas emissions, Governments around the world are dependent on reliable estimates of CO₂ storage capacity and insightful indications of the viability of geological storage in their respective jurisdictions. Similarly, industry needs reliable estimates for business decisions regarding site selection and development. If such estimates are unreliable, and decisions are made based on poor advice, then valuable resources and time could be wasted. Policies that have been put in place to address CO₂ emissions could be jeopardised. Estimates need to clearly state the limitations that existed (data, time, knowledge) at the time of making the assessment and indicate the purpose and future use to which the estimates should be applied. A set of guidelines for estimation of storage capacity will greatly assist future deliberations by government and industry on the appropriateness of geological storage of CO₂ in different geological settings and political jurisdictions. This work has been initiated under the auspices of the Carbon Sequestration Leadership Forum (www.cslforum.org), and it is intended that it will be an ongoing taskforce to further examine issues associated with storage capacity estimation.     

Geochemical and solute transport modelling for CO2 storage, what to expect from it?

Geochemistry plays an important role when assessing the impact of CO₂ storage. Due to the potential corrosive character of CO₂, it might affect the chemical and physical properties of the wells, the reservoir and its surroundings and increase the environmental and financial risk of CO₂ storage projects in deep geological structures. An overview of geochemical and solute transport modelling for CO₂ storage purposes is given, its data requirements and gaps are highlighted, and its progress over the last 10 years is discussed. Four different application domains are identified: long-term integrity modelling, injectivity modelling, well integrity modelling and experimental modelling and their current state of the art is discussed. One of the major gaps remaining is the lack of basic thermodynamical and kinetic data at relevant temperature and pressure conditions for each of these four application domains. Real challenges are the coupled solute transport and geomechanical modelling, the modelling of impurities in the CO₂ stream and pore-scale modelling applications.     

Long-term variations of CO2 trapped in different mechanisms in deep saline formations: A case study of the Songliao Basin,China

The geological storage of CO₂ in deep saline formations is increasing seen as a viable strategy to reduce the release of greenhouse gases to the atmosphere. There are numerous sedimentary basins in China, in which a number of suitable CO₂ geologic reservoirs are potentially available. To identify the multi-phase processes, geochemical changes and mineral alteration, and CO₂ trapping mechanisms after CO₂ injection, reactive geochemical transport simulations using a simple 2D model were performed. Mineralogical composition and water chemistry from a deep saline formation of Songliao Basin were used. Results indicate that different storage forms of CO₂ vary with time. In the CO₂ injection period, a large amount of CO₂ remains as a free supercritical phase (gas trapping), and the amount dissolved in the formation water (solubility trapping) gradually increases. Later, gas trapping decrease, solubility trapping increases significantly due to the migration and diffusion of CO₂ plume and the convective mixing between CO₂-saturated water and unsaturated water, and the amount trapped by carbonate minerals increases gradually with time. The residual CO₂ gas keeps dissolving into groundwater and precipitating carbonate minerals. For the Songliao Basin sandstone, variations in the reaction rate and abundance of chlorite, and plagioclase composition affect significantly the estimates of mineral alteration and CO₂ storage in different trapping mechanisms. The effect of vertical permeability and residual gas saturation on the overall storage is smaller compared to the geochemical factors. However, they can affect the spatial distribution of the injected CO₂ in the formations. The CO₂ mineral trapping capacity could be in the order of 10 kg/m³ medium for the Songliao Basin sandstone, and may be higher depending on the composition of primary aluminosilicate minerals especially the content of Ca, Mg, and Fe.     

Preliminary assessment of CO2 geological storage opportunities in Greece

This paper provides a preliminary assessment of the suitability of Tertiary sedimentary basins in Northern, Western and Eastern Greece in order to identify geological structures close to major CO₂ emission sources with the potential for long-term storage of CO₂. The term “emissions” refers to point source emissions as defined by the International Energy Agency, including power generation, the cement sector and other industrial processes. The Prinos oil field and saline aquifer, along with the saline formations of the Thessaloniki Basin and the Mesohellenic Trough have been identified as prospective CO₂ geological storage sites. In addition, a carbonate deep saline aquifer occurring at appropriate depths beneath the Neogene-Quaternary sediments of Ptolemais-Kozani graben (NW Greece) is considered. The proximity of this geological formation to Greece's largest lignite-fired power plants suggests that it would be worthwhile undertaking further site-specific studies to quantify its storage capacity and assess its structural integrity.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.     

Geological storage of CO2 in saline aquifers—A review of the experience from existing storage operations

The experience from CO₂ injection at pilot projects (Frio, Ketzin, Nagaoka, US Regional Partnerships) and existing commercial operations (Sleipner, Snøhvit, In Salah, acid-gas injection) demonstrates that CO₂ geological storage in saline aquifers is technologically feasible. Monitoring and verification technologies have been tested and demonstrated to detect and track the CO₂ plume in different subsurface geological environments. By the end of 2008, approximately 20 Mt of CO₂ had been successfully injected into saline aquifers by existing operations. Currently, the highest injection rate and total storage volume for a single storage operation are approximately 1 Mt CO₂/year and 25 Mt, respectively. If carbon capture and storage (CCS) is to be an effective option for decreasing greenhouse gas emissions, commercial-scale storage operations will require orders of magnitude larger storage capacity than accessed by the existing sites. As a result, new demonstration projects will need to develop and test injection strategies that consider multiple injection wells and the optimisation of the usage of storage space. To accelerate large-scale CCS deployment, demonstration projects should be selected that can be readily employed for commercial use; i.e. projects that fully integrate the capture, transport and storage processes at an industrial emissions source.