The consequences of failure should be considered in siting geologic carbon sequestration projects

Geologic carbon sequestration is the injection of anthropogenic CO₂ into deep geologic formations where the CO₂ is intended to remain indefinitely. If successfully implemented, geologic carbon sequestration will have little or no impact on terrestrial ecosystems aside from the mitigation of climate change. However, failure of a geologic carbon sequestration site, such as large-scale leakage of CO₂ into a potable groundwater aquifer, could cause impacts that would require costly remediation measures. Governments are attempting to develop regulations for permitting geologic carbon sequestration sites to ensure their safety and effectiveness. At present, these regulations focus largely on decreasing the probability of failure. In this paper we propose that regulations for the siting of early geologic carbon sequestration projects should emphasize limiting the consequences of failure because consequences are easier to quantify than failure probability.     

Numerical investigation concerning the impact of CO2 geologic storage on regional groundwater flow

Large-scale storage of carbon dioxide in saline aquifers may cause considerable pressure perturbation and brine migration in deep rock formations, which may have a significant influence on the regional groundwater system. With the help of parallel computing techniques, we conducted a comprehensive, large-scale numerical simulation of CO₂ geologic storage that predicts not only CO₂ migration, but also its impact on regional groundwater flow. As a case study, a hypothetical industrial-scale CO₂ injection in Tokyo Bay, which is surrounded by the most heavily industrialized area in Japan, was considered, and the impact of CO₂ injection on near-surface aquifers was investigated, assuming relatively high seal-layer permeability (higher than 10 microdarcy). A regional hydrogeological model with an area of about 60 km × 70 km around Tokyo Bay was discretized into about 10 million gridblocks. To solve the high-resolution model efficiently, we used a parallelized multiphase flow simulator TOUGH2-MP/ECO2N on a world-class high performance supercomputer in Japan, the Earth Simulator. In this simulation, CO₂ was injected into a storage aquifer at about 1 km depth under Tokyo Bay from 10 wells, at a total rate of 10 million tons/year for 100 years. Through the model, we can examine regional groundwater pressure buildup and groundwater migration to the land surface. The results suggest that even if containment of CO₂ plume is ensured, pressure buildup on the order of a few bars can occur in the shallow confined aquifers over extensive regions, including urban inlands.     

Large-scale impact of CO2 storage in deep saline aquifers: A sensitivity study on pressure response in stratified systems

Large volumes of CO₂ captured from carbon emitters (such as coal-fired power plants) may be stored in deep saline aquifers as a means of mitigating climate change. Storing these additional fluids may cause pressure changes and displacement of native brines, affecting subsurface volumes that can be significantly larger than the CO₂ plume itself. This study aimed at determining the three-dimensional region of influence during/after injection of CO₂ and evaluating the possible implications for shallow groundwater resources, with particular focus on the effects of interlayer communication through low-permeability seals. To address these issues quantitatively, we conducted numerical simulations that provide a basic understanding of the large-scale flow and pressure conditions in response to industrial-scale CO₂ injection into a laterally open saline aquifer. The model domain included an idealized multilayered groundwater system, with a sequence of aquifers and aquitards (sealing units) extending from the deep saline storage formation to the uppermost freshwater aquifer. Both the local CO₂-brine flow around the single injection site and the single-phase water flow (with salinity changes) in the region away from the CO₂ plume were simulated. Our simulation results indicate considerable pressure buildup in the storage formation more than 100 km away from the injection zone, whereas the lateral distance migration of brine is rather small. In the vertical direction, the pressure perturbation from CO₂ storage may reach shallow groundwater resources only if the deep storage formation communicates with the shallow aquifers through sealing units of relatively high permeabilities (higher than 10^?18 m²). Vertical brine migration through a sequence of layers into shallow groundwater bodies is extremely unlikely. Overall, large-scale pressure changes appear to be of more concern to groundwater resources than changes in water quality caused by the migration of displaced saline water.     

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO₂) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO₂ injection may have a limiting effect on CO₂ storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO₂ storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO₂ occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO₂ storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO₂ and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.     

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.     

CLIMATE CHANGE IMPACTS UNCERTAINTY FOR WATER RESOURCES IN THE SAN JOAQUIN RIVER BASIN,CALIFORNIA1

ABSTRACT: A climate change impacts assessment for water resources in the San Joaquin River region of California is presented. Regional climate projections are based on a 1 percent per year CO₂ increase relative to late 20th Century CO₂ conditions. Two global projections of this CO₂ increase scenario are considered (HadCM2 and PCM) during two future periods (2010 to 2039 and 2050 to 2079). HadCM2 projects faster warming than PCM. HadCM2 and PCM project wetter and drier conditions, respectively, relative to present climate. In the HadCM2 case, there would be increased reservoir inflows, increased storage limited by existing capacity, and increased releases for deliveries and river flows. In the PCM case, there would be decreased reservoir inflows, decreased storage and releases, and decreased deliveries. Impacts under either projection case cannot be regarded as more likely than the other. Most of the impacts uncertainty is attributable to the divergence in the precipitation projections. The range of assessed impacts is too broad to guide selection of mitigation projects. Regional planning agencies can respond by developing contingency strategies for these cases and applying the methodology herein to evaluate a broader set of CO₂ scenarios, land use projections, and operational assumptions. Improved agency access to climate projection information is necessary to support this effort.     

Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.     

Evaluating geological sequestration of CO2 in bituminous coals: The southern Sydney Basin,Australia as a natural analogue

Carbon dioxide contents of coals in the Sydney Basin vary both aerially and stratigraphically. In places, the coal seam gas is almost pure CO₂ that was introduced from deep magmatic sources via faults and replaced pre-existing CH₄. In some respects this process is analogous to sequestration of anthropogenic CO₂. Laboratory studies indicate that CO₂:CH₄ storage capacity ratios for Sydney Basin coals are up to ∼2 and gas diffusivity is greater for CO₂ by a factor of up to 1.5.Present-day distribution of CO₂ in the coals is controlled by geological structure, depth and a combination of hydrostatic and capillary pressures. Under present-day P–T conditions, most of the CO₂ occurs in solution at depths greater than about 650 m; at shallower depths, larger volumes of CO₂ occur in gaseous form and as adsorbed molecules in the coal due to rapidly decreasing CO₂ solubility. The CO₂ has apparently migrated up to structural highs and is concentrated in anticlines and in up-dip sections of monoclines and sealing faults. CO₂ sequestered in coal measure sequences similar to those of the Sydney Basin may behave in a similar way and, in the long term, equilibrate according to the prevailing P–T conditions.In situ CO₂ contents of Sydney Basin coals range up to 20 m³/t. Comparisons of adsorption isotherm data measured on ground coal particles with in situ gas contents of Sydney Basin coals indicate that the volumes of CO₂ stored do not exceed ∼60% of the total CO₂ storage capacity. Therefore, the maximum CO₂ saturation that may be achieved during sequestration in analogous coals is likely to be considerably lower than the theoretical values indicated by adsorption isotherms.     

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.     

Site selection in CO2 ocean sequestration: Dependence of CO2 injection rate on eddy activity distribution

Site selection in CO₂ ocean sequestration is examined based on the idea that a site where injected CO₂ is efficiently diluted is favourable in reducing/avoiding biological impacts. Simulations of CO₂ injection into several sites by an eddy-resolving oceanic general circulation model (OGCM) show that the maximum CO₂ concentration differs by a factor of 10 among sites. The distribution of eddy activity is the most important causative factor producing the geographical differences in CO₂ dilution. Based on the relationship between the maximum CO₂ concentration and eddy activity, we estimated the distribution of the maximum CO₂ injection rate by a proposed method, which does not cause chronic impacts on biota. Around Japan, extensive ocean volume has the potential to dilute 20 million tonnes per year without chronic impacts, and some areas can be injected with 80 million tonnes per year.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

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.     

An updated assessment of the acute impacts of ocean carbon sequestration by direct injection

This paper evaluates the expected environmental impact of several promising schemes for ocean carbon sequestration by direct injection of CO₂, and serves as a major update to the assessment by Auerbach et al. (1997) and Caulfield et al. (1997) of water quality impacts and the induced mortality to zooplankton. Three discharge approaches are considered, each designed to maximize dilution over the water column: a point release of negatively buoyant CO₂ hydrate particles from a moving ship; a stationary point release of CO₂ hydrate particles forming a sinking plume; and a long, bottom-mounted diffuser discharging buoyant liquid CO₂ droplets. Two of these scenarios take advantage of the enhanced dilution offered by CO₂ hydrate particles, and are based on recent laboratory and field studies on the formation and behavior of such particles. Overall, results suggest that it is possible with present or near present technology to engineer discharge configurations that achieve sufficient dilution to largely avoid acute impacts. In particular, the moving ship hydrate discharge is identified as the most promising due to its operational flexibility. In addition to lethal effects, sub-lethal and ecosystem effects are discussed qualitatively, though not analyzed quantitatively. Our main conclusion is that ocean carbon sequestration by direct injection should not be dismissed as a climate change mitigation strategy on the basis of environmental impact alone. Rather, it can be considered as a viable option for further study, especially in regions where geologic sequestration proves impractical.     

Evaluation of large-scale CO2 storage on fresh-water sections of aquifers: An example from the Texas Gulf Coast Basin

Large-scale injections of CO₂ into subsurface saline aquifers have been proposed to remediate climate change related to buildup of green house gases in the atmosphere. The pressure buildup caused by such injections may impact a volume of the basin significantly larger than the CO₂ plume itself. In areas with hydrological settings similar to the Gulf Coast Basin, the perturbation of the flow-field in deep parts of the basin could result in brines or brackish water being pushed up-dip into unconfined sections of the same formations or into the capture zone of fresh-water wells. The premise of the current study is that the details of multiple-phase flow processes necessary to model the near field evolution of the CO₂ plume are not necessary to describe the impact of the pressure anomaly on up-dip aquifers. This paper quantitatively explores conditions under which shallow groundwater would be impacted by up-dip displacement of brines, utilizing an existing carefully calibrated flow model. Modeling an injection of water, arguably equivalent to 50 million tons of CO₂/year for 50 years resulted in an average water-table rise of 1 m, with minor increase in stream baseflow and larger increase in ground water evapotranspiration, but no significant change in salinity.     

Legal and regulatory challenges in the implementation of CO2 geological storage: An Alberta and Canadian perspective

Alberta is the province with the largest CO₂ emissions in Canada, with approximately two-thirds of emissions originating from large stationary sources. Due to the fortuitous association of large CO₂ sources with the storage capacity offered by the underlying Alberta basin, it is expected that large-scale CO₂ geological storage in Canada will occur in Alberta first, and both levels of governments are contemplating measures to facilitate implementation. A review of the current provincial and federal legislation and regulations presented in this paper indicates that the existing legal and regulatory regime is reasonably sufficient, with some modifications, to accommodate the active injection phase of CO₂ capture and storage (CCS) operations, and the early takers of this new technology. However, governments in Alberta and Canada, and likely everywhere, need to address several pressing issues dealing mainly with the CCS post-operational phase. These issues, reviewed in this paper from an Alberta and Canadian perspective, fall into several categories: jurisdictional, property (ownership), regulatory and liability. Because Alberta is a landlocked province, matters relating to CO₂ storage under the seabed will not be addressed here except when discussing matters of jurisdiction and CO₂ classification. Possible models for post-injection liability transfer to the state are also presented. Although this review is focused on western Canada conditions, the issues are broad enough to be of interest in other jurisdictions, which may also adopt parts of the legal and regulatory framework that is quite well developed in Alberta.     

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.     

Investigations on CO2 storage capacity in saline aquifers—Part 2: Estimation of storage capacity coefficients

Many studies on geological carbon dioxide (CO₂) storage capacity neglect the influence of complex coupled processes which occur during and after the injection of CO₂. Storage capacity is often overestimated since parts of the reservoirs cannot be reached by the CO₂ plume due to gravity segregation and are thus not accessible for storage. This work investigates the effect of reservoir parameters like depth, temperature, absolute and relative permeability, and capillary pressure on the processes during CO₂ injection and thus on estimates of effective storage capacity. The applied statistical characteristics of parameters are based on a large reservoir parameter database. Different measured relative permeability relations are considered. The methodology of estimating storage capacity is discussed. Using numerical 1D and 3D experiments, detailed time-dependent storage capacity estimates are derived. With respect to the concept developed in this work, it is possible to estimate effective CO₂ storage capacity in saline aquifers. It is shown that effective CO₂ mass stored in the reservoir varies by a factor of 20 for the reservoir setups considered. A high influence of the relative permeability relation on storage capacity is shown.     

The potential for increased atmospheric CO2 emissions and accelerated consumption of deep geologic CO2 storage resources resulting from the large-scale deployment of a CCS-enabled unconventional fossil fuels industry in the U.S.

Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO₂) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO₂ storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO₂ from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO₂ capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO₂ emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO₂, in addition to storing potentially 900–5000 MtCO₂ in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO₂ emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO₂ stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO₂ storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO₂ storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.     

A natural analogue for CO2 mineral sequestration in Miocene basalt in the Kuanhsi-Chutung area, Northwestern Taiwan

In general, CO₂ sequestration by carbonation is estimated by laboratory experimentation and geochemical simulation. In this study, however, estimation is based on a natural analogue study of the Miocene basalt in the Kuanhsi-Chutung area, Northwestern Taiwan. This region has great potential in terms of geological and geochemical environments for CO₂ sequestration. Outcropping Miocene basalt in the study area shows extensive serpentinization and carbonation. The carbon stable isotopes of carbonates lie on the depleted side of the Lohmann meteoric calcite line, which demonstrates that the carbonates most probably precipitate directly from meteoric fluid, and water–rock interaction is less involved in the carbonation process. Oxygen stable isotope examinations also show much depleted ratios, representative of product formation under low temperatures (∼50–90 °C). This translates to a depth of 1–2 km, which is a practical depth for a CO₂ sequestration reservoir. According to petrographic observation and electron microprobe analysis, the diopside grains in the basalt are resistant to serpentinization and carbonation; therefore, the fluid causing alteration is likely enriched with calcium and there must be additional sources of calcium for carbon mineralization. These derived geochemical properties of the fluid support the late Miocene sandstone and enclosed basalts as having high potential for being a CO₂ sequestration reservoir. Moreover, the existing geochemical environments allow for mineralogical assemblages of ultramafic xenoliths, indicating that forsterite, orthopyroxene and feldspar minerals are readily replaced by carbonates. Based on the mineral transformation in xenoliths, the capacity of CO₂ mineral sequestration of the Miocene basalt is semi-quantitatively estimated at 94.15 kg CO₂ chemically trapped per 1 m³ basalt. With this value, total CO₂ sequestration capacity can be evaluated by a geophysical survey of the amount of viable Miocene basalt at the potential sites. Such a survey is required in the near future.     

An engineering-economic model of pipeline transport of CO2 with application to carbon capture and storage

Carbon dioxide capture and storage (CCS) involves the capture of CO₂ at a large industrial facility, such as a power plant, and its transport to a geological (or other) storage site where CO₂ is sequestered. Previous work has identified pipeline transport of liquid CO₂ as the most economical method of transport for large volumes of CO₂. However, there is little published work on the economics of CO₂ pipeline transport. The objective of this paper is to estimate total cost and the cost per tonne of transporting varying amounts of CO₂ over a range of distances for different regions of the continental United States. An engineering-economic model of pipeline CO₂ transport is developed for this purpose. The model incorporates a probabilistic analysis capability that can be used to quantify the sensitivity of transport cost to variability and uncertainty in the model input parameters. The results of a case study show a pipeline cost of US$ 1.16 per tonne of CO₂ transported for a 100 km pipeline constructed in the Midwest handling 5 million tonnes of CO₂ per year (the approximate output of an 800 MW coal-fired power plant with carbon capture). For the same set of assumptions, the cost of transport is US$ 0.39 per tonne lower in the Central US and US$ 0.20 per tonne higher in the Northeast US. Costs are sensitive to the design capacity of the pipeline and the pipeline length. For example, decreasing the design capacity of the Midwest US pipeline to 2 million tonnes per year increases the cost to US$ 2.23 per tonne of CO₂ for a 100 km pipeline, and US$ 4.06 per tonne CO₂ for a 200 km pipeline. An illustrative probabilistic analysis assigns uncertainty distributions to the pipeline capacity factor, pipeline inlet pressure, capital recovery factor, annual O&M cost, and escalation factors for capital cost components. The result indicates a 90% probability that the cost per tonne of CO₂ is between US$ 1.03 and US$ 2.63 per tonne of CO₂ transported in the Midwest US. In this case, the transport cost is shown to be most sensitive to the pipeline capacity factor and the capital recovery factor. The analytical model elaborated in this paper can be used to estimate pipeline costs for a broad range of potential CCS projects. It can also be used in conjunction with models producing more detailed estimates for specific projects, which requires substantially more information on site-specific factors affecting pipeline routing.