CO2 Geological Storage Site Research Articles

Dissolution kinetics of hydrated calcium aluminates (AFm-Cl) as a function of pH and at room temperature

AbstractThe determination of reliable weathering/dissolution rates for cement phases is of fundamental importance for the modelling of the temporal evolution of both radioactive waste repositories and CO2 geological storage sites (e.g. waste matrix, plug in boreholes). Here, the dissolution kinetics of AFm-Cl (hydrated calcium aluminates containing interlayer Cl) has been studied using flow-through experiments conducted at pH values ranging from 9.2 to 13. Mineralogical (XRD) and chemical (EPMA, TEM) analyses have been performed to determine the evolution of the phases during the dissolution experiments. For pH values between 10 and 13, the dissolution of AFm-Cl is congruent (i.e. Ca/Al ratios close to 2 both for solids and outlet concentrations). In contrast, the precipitation of amorphous Al-phases and possibly amorphous mixed Al/Ca phases is observed at pH 9.2, leading to Ca/Al ratios in the outlet solutions higher than those of the initial solid. Therefore, at pH 9.2, even if Cl–/OH– exchange occurs, estimation of dissolution rate from released Cl appears to be the best proxy. Dissolution rates were normalized to the final specific surface areas (ranging from 6.1 to 35.4 m2 g−1). Dissolution rate appears to be pH-independent and therefore the far-from-equilibrium dissolution rate at room temperature is expressed as: logR(mol m–2 s–1) = –9.23 ± 0.18

Focused fluid flow and the sub-seabed storage of CO2: Evaluating the leakage potential of seismic chimney structures for the Sleipner CO2 storage operation

The integrity of the caprock of a storage formation is the most crucial parameter for the long-term performance of a geological CO2 storage site. The Sleipner area in the Southern Viking Graben hosts the first and longest operating industrial scale CO2 storage project, where CO2 is injected in a saline aquifer of the Utsira Formation. Time-lapse seismic monitoring shows neither that CO2 has left the Utsira Formation nor indications for fracturing of the caprock by the CO2 injection activity, which is in agreement with previous numerical simulations. However, large chimney structures as close as 7 km from the injection point indicate that the caprock has been breached in the geological past, which may raise questions about the integrity of the caprock above the Sleipner CO2 storage site. Here, we present seismically constrained numerical fluid flow simulations that evaluate the influence of chimney structures on the long-term performance of the CO2 storage operation at Sleipner. The simulation could reproduce the spreading of the Sleipner CO2 plume, which is controlled by the anisotropic permeability field of the Utsira Formation and the regional dip of the formation top. We have performed long-term plume evolution simulations, which show that the injected CO2 will not reach the existing chimney structures assuming a realistic injection duration of 30 years. Our simulations indicate that an unrealistically long injection period between 92 and 140 years would be required for the CO2 to reach the existing chimney structures. In this case, a comparably low chimney permeability of 10 mD may be sufficient to facilitate CO2 migration from the storage formation to the seafloor, once the CO2 has reached a chimney structure. However, the simulations indicate that it is very unlikely that the CO2 may migrate along existing chimney structures at Sleipner. Our results highlight that the reconstruction of palaeo fluid flow systems and the identification of focused fluid conduits should be considered in the assessment of CO2 storage sites.

Informing Geologic CO2 Storage Site Management Decisions under Uncertainty: Demonstration of NRAP's Integrated Assessment Model (NRAP-IAM-CS) Application

Managing risks at geologic CO2 storage sites requires making decisions based on the quantitative predictions of long-term performance that not only take into account various subsurface hydrologic, geochemical processes and interactions but also the related uncertainties. The US DOE (United States Department of Energy) funded National Risk Assessment Partnership (NRAP) has developed a quantitative approach and a model to predict the long-term behavior of GCS sites. The approach uses an integrated assessment model (NRAP-IAM-CS) that couples reduced order models (ROMs) for various GCS components (such as storage reservoir, wells, seals, and groundwater aquifer) in a stochastic modeling framework that allows for rapid simulations of entire system behavior over thousands of years while probing uncertainties. We demonstrate application of NRAP-IAM-CS using two examples that focus on CO2 leakage and resulting impacts. The examples are used to demonstrate how different uncertain parameters affect overall performance objectives.

Towards a Method for Leakage Quantification and Remediation Monitoring in the Near-surface at Terrestrial CO2 Geologic Storage Sites

The Intergovernmental Panel on Climate Change (IPCC) states that quantification of leakage emissions at CO2 geological storage sites will require direct monitoring techniques rather than standardized emissions factors. In addition, IPCC guidelines state that leakage emissions should be distinguished from natural baseline emissions. Current methods measure only bulk CO2 emissions and therefore do not have the capability to separate these components. We discuss that a process-based soil gas approach could potentially be used with an open chamber emissions quantification method to translate process-based concentration data into surface flux rates. In doing so, the various components of surface gas flux could be attributed, separated and individually quantified. We use soil gas data from the ZERT controlled release experimental site as the basis for our discussion and show that such a method may improve the accuracy and ease of leakage quantification. For accounting purposes, such capabilities could be used to more accurately assess the number of credits to be surrendered for leakage. For monitoring purposes, added benefits could include delineating the spatial extent of leakage emissions and providing real-time information on the effectiveness of remediation efforts.

Trapping Mechanisms in Field Scale: Results from Nagaoka Geologic CO2 Storage Site

The importance of capillary and solubility trappings has been reported, since they contribute the integrity of CO2 sequestration from the early stage of CO2 storage. This paper reports contribution of these trappings in field scale derived from the logging data at the Nagaoak site. At this site, loggings for the monitoring purpose have been conducted for more than 12 years and about 11 years during the post-injection period. From the neutron logging CO2 saturation was evaluated, and the negative anomaly in the induction logging accounted for the solubility trapping. The relationship between the maximum and the latest CO2 saturation was used to investigate the initial-residual (IR) curve at the site. The IR curve obtained from the down-dip position showed that a Land's model could explain the hysteretic flow properties. These results among the observation wells could be used to interpret the migration of CO2 in the reservoir. The results from induction logging indicated that solubility trapping was progressing as diffusion process. These results could be used for the calibration of two-phase flow models for the long-term behavior of CO2 in geological storage site.

Assessing Interactions between Multiple Geological CO2 Storage Sites to Optimize Capacity in Regionally Extensive Storage Sandstones

The potential resource for carbon dioxide (CO2) storage in strata underlying the North Sea is mostly within brine-saturated sandstone formations which are each many hundreds to thousands of square kilometres in extent. The immense potential to store CO2 in these rocks can only be fully achieved by the operation of more than one injection site within each formation.A UK North Sea case study anticipates the operation of two injection sites in the Captain Sandstone and assesses any interaction between the injection sites. Technical investigations to optimize the storage capacity in a regionally extensive North Sea sandstone by the operation of more than one injection site within a storage formation [1] are summarised: geological modelling; geomechanical modelling; simulation of CO2 injection; monitoring planning. The UK case study includes the Goldeneye Field, the storage site investigated for the planned Peterhead CCS project. An injection scenario was examined that comprised an initial project storing within a depleted hydrocarbon field structure followed by a second injection site within the surrounding saline aquifer. The research investigations were targeted to identify and reduce any perceived concerns specific to the operation of two sites by a risk assessment-led process. Requirements for a monitoring plan specific to a multi-user storage formation, based on the prediction of storage site performance, were also developed. Generic learning applicable to any suitable multi-user storage sandstone was captured, from the process followed and the technical knowledge acquired, on the characterisation of extensive sandstone formations, management of the planned injection operations and monitoring planning.

Effect of Permeability Heterogeneity on Area of Review

The Area of Review is one of the most important aspects of a geologic CO2 storage site permit application and regulatory requirement. The US Environmental Protection Agency (EPA) has implemented an Area of Review (AoR) requirement for Class VI CO2 injection wells for geologic sequestration. Reservoir permeability is one of the most important parameters controlling AoR evolution but is generally highly heterogeneous and difficult to constrain. We have used a numerical model for Rock Springs Uplift in Wyoming as an example site to characterize how the heterogeneity in reservoir permeability affects AoR. We have performed multiple reservoir simulations using multiple, equally-likely realizations of heterogeneous permeability. We considered multiple CO2 injection scenarios with varying injection rates as well as varying injection and post-site durations. Results of our study demonstrate that uncertainty in permeability heterogeneity can significantly influence AoR for both CO2 saturation and pressure. In our example, the CO2 AoR varied by as much as 2-3 times while the pressure AoR varied over 1.5 – 2 times. Such type of variability can have significant implications in defining AoR for site permit applications.

A Field Demonstration of an Active Reservoir Pressure Management through Fluid Injection and Displaced Fluid Extraction at the Rock Springs Uplift a Priority Geologic CO2 Storage Site for Wyoming

The University of Wyoming is partnered with Los Alamos National Laboratory, Lawrence Livermore National Laboratory, Battelle, and Water system Specialists Inc. to carry out a DOE funded brine extraction storage test (BEST) project at the Rock Springs Uplift (RSU), southwest Wyoming. The BEST projects are envisioned using a two-phased approach. The initial phase is 1) to predict and monitor the differential pressure and injected fluid movement, and manage changes in formation pressure, and 2) to develop a test-bed for deploying treatment technologies for extracted brines.The RSU shows promise as a CO2 storage location because of its favorable geologic conditions and structure. In addition, the project is located at a carbon storage site in southwest Wyoming that has been extensively characterized on the basis of data obtained from previous U.S. DOE-funded studies that have included detailed site descriptions and CO2 storage capacity and permanence estimates. The primary objective of the project includes:•Refining 3-D reservoir structure and property models of the site that include the known structural complexity and heterogeneity of the site's subsurface conditions;•Evaluate geophysical and chemical monitoring technologies and techniques to detect and measure pressure response to injected fluid as well as track fluid migration pathways;•Analyze the feasibility of extracting formation brine water to mitigate the pressure increase from injection, as well as to modify the pressure front, resulting in the ability to manipulate the direction of the migrating pressure/CO2 plume, and reduce the size of the Area of Review;•Develop advanced fluid flow simulation schemes to predict reservoir pressure responses and migration pathways of the injected fluid;•Implement rock mechanical property and stress calculations, combined with simulations, to help assess geomechanical impacts to the reservoir and confining layers in response to high volume CO2 injections;•Conduct a produced brine life-cycle analysis, and develop a displaced brine water treatment, and management program; and•Propose an active reservoir management strategy that could be implemented during a field testing.The proposed field test project includes developing a field site fully capable of fluid injection, production, monitoring, and water treatment. This effort would provide for in-situ testing of plume migration and pressure management strategies, and investigate the technical feasibility of treating co-produced waters. Furthermore, the result of this effort is a better understanding of the potential effects of pressure and active brine management on the behavior of stored CO2 in the Rocky Mountain region as well as the similar saline aquifers around world, such as the huge saline aquifer in the Ordos Basin, China.

Review of Project Permits under the London Protocol – An Assessment of the Proposed P18-4 CO2 Storage Site

The London Protocol (1996) is a global agreement to promote the protection of the marine environment by prohibiting the dumping of wastes and other matter into the sea. Under the Protocol all dumping is prohibited, with the exception of a limited number of selected wastes on the so-called “reverse list”, which can be considered for dumping. In 2007, an amendment entered into force which permitted CO2 streams to be considered for dumping under the London Protocol. The amendment was shortly followed up with a set of “Specific Guidelines for Assessment of Carbon Dioxide Streams for Disposal into Sub-seabed Geological Formations”, developed to support the National Authorities of Contracting Parties in evaluating permit applications for CO2 disposal activities in their marine territories. The objective of this report is to assess to what extent the proposed P18-4 CO2 geological storage site in the Dutch North Sea, originally part of the ROAD CCS Project, complies with the aforementioned guidelines, and therefore the 1996 London Protocol itself. The assessment has been achieved through a simple, but systematic, cross check of the requirements of the guideline against the contents of the application material provided by the operator to the National Authority. This assessment finds that the material submitted to the National Authority is broadly sufficient to allow an evaluation of the planned CO2 storage activities in a manner consistent with the provisions of the 1996 London Protocol. The assessment indicates overall technical compliance with the CO2 Specific Guidelines, with no information sufficiently absent to indicate clear non-compliance. There are, however, eight areas from within the application material whereby the information or justification is partially sufficient, but may require further clarification, and one area of non-compliance from within the permit conditions, which is the responsibility of the National Authority. A number of recommendations are provided.

The physical characteristics of a CO2 seeping fault: The implications of fracture permeability for carbon capture and storage integrity

To ensure the effective long-term storage of CO2 in candidate geological storage sites, evaluation of potential leakage pathways to the surface should be undertaken. Here we use a series of natural CO2 seeps along a fault in South Africa to assess the controls on CO2 leakage to the surface. Geological mapping and detailed photogrammetry reveals extensive fracturing along the mapped fault trace. Measurements of gas flux and CO2 concentration across the fracture corridor give maximum soil gas measurements of 27% CO2 concentration and a flux of 191gm−2d−1. These measurements along with observations of gas bubbles in streams and travertine cones attest to CO2 migration to the surface. Permeability measurements on the host rock units show that the tillite should act as an impermeable seal to upward CO2 migration. The combined permeability and fracture mapping data indicate that fracture permeability creates the likely pathway for CO2 migration through the low permeability tillite to the surface. Heterogeneity in fracture connectivity and intensity at a range of scales will create local higher permeability pathways along the fracture corridor, although these may seal with time due to fluid-rock interaction. The results have implications for the assessment and choice of geological CO2 storage sites, particularly in the assessment of sub-seismic fracture networks.

Gas source attribution techniques for assessing leakage at geologic CO2 storage sites: Evaluating a CO2 and CH4 soil gas anomaly at the Cranfield CO2-EOR site

At the Cranfield CO2 enhanced oil recovery (CO2-EOR) site, a localized area of high concentrations of CO2 (up to 44%) and CH4 (up to 47%) in soil gas was detected near a plugged and abandoned well. The complexity of attributing this anomaly, especially in a CO2-EOR setting, underscores the need for careful attribution techniques and provides rare and valuable experiential knowledge on attributing blind anomalies. An extensive geochemical monitoring program utilizing process-based soil gas ratios, stable and radioactive isotopes of CO2 and CH4, light hydrocarbon concentrations, noble gases, and perfluorocarbon and sulfur hexafluoride tracers was undertaken from 2009 through 2014. The goals were to attribute source, assess the usefulness of various attribution techniques, and begin to develop a framework for attribution in complex CO2-EOR settings. Initial process-based assessment indicated an “exogenous” source meaning that it was not the result of natural in-situ processes (Romanak et al., 2012). We report on the additional analyses used to determine the degree to which the anomaly was related to CO2 injection. This work included characterization of potential non-reservoir gas sources within the overburden using mud-gas samples collected during a new drill and downhole fluids collected from wells within the field. Two hydrocarbon gas sources, one within the reservoir (Tuscaloosa) and one in the above-zone (Wilcox) were geochemically distinct. Stable carbon isotopes (δ13C) of CH4 in the anomaly were similar to those of the reservoir, but stable hydrogen isotopes (δD) indicated that anomalous gases originate from an undetermined microbial source rather than either of the subsurface gas reservoirs. Hydrocarbon geochemical parameters were therefore not only useful for attribution, but were also found to have a high potential for leading to inaccurate conclusions because of alteration via CH4 oxidation. Noble gases and introduced tracers proved least effective for attribution in this case. The most useful indicator was radioactive isotopes of CO2 and CH4, which contained >100% modern carbon indicating a negligible input, if any, from the reservoir.

Monitoring of injected CO2 at two commercial geologic storage sites with significant pressure depletion and/or re-pressurization histories: A case study

Abstract Majority of geologic CO2 storage sites for currently operated large-scale integrated carbon capture and storage projects (LSIPs) in operation around the world are depleted oil fields that have been undergone significant depletion and re-pressurization prior to injection of captured CO2. A better understanding of any of the implications associated with past depletion and re-pressurization histories to “out of injection zone” migration of injected CO2 can help in making monitoring strategies significantly more effective. Being the geologic CO2 storage demonstration sites for two most active LSIPs in the US, the West Hastings and the Bell Creek Oil Fields are the main focus of present study. The monitoring technologies that have been used/deployed/tested at both the normally pressured West Hastings and the subnormally pressured Bell Creek storage sites appear to adequately address any of the potential “out of zone migration” of injected CO2 at these sites. It would be interesting to see if any of the collected monitoring data at the West Hastings and the Bell Creek storage sites could also be used in future to better understand the viability of initially subnormally pressured and subsequently depleted and re-pressurized oil fields as secure geologic CO2 storage sites with relatively large storage CO2 capacities compared to the depleted and re-pressurized oil fields that were initially discovered as normally pressured.

Experimental mechanical compaction of reconstituted shale and mudstone aggregates: Investigation of petrophysical and acoustic properties of SW Barents Sea cap rock sequences

This study investigates petrophysical and acoustic properties of experimentally compacted reconstituted samples of seal sequences from the southwestern Barents Sea. The aggregates were collected from drill cuttings of mudstone and shale formations of two exploration wells, 7220/10-1 (Salina discovery) and 7122/7-3 (Goliat field). The washed and freeze-dried samples were characterized for grain size distributions, geochemical analyses, and mineralogical compositions. A total of 25 compaction tests (12 dry and 13 brine-saturated) were performed with a maximum effective vertical stress of 50 MPa. The laboratory measurements demonstrated that petrophysical and acoustic properties of argillaceous sediments can change within a sedimentary basin and even within a given formation. The results show that the collected aggregates from Goliat field are compacted more compared to Salina discovery. The maximum and minimum compaction are measured in samples collected from Snadd and Fuglen formations, respectively. The final porosity of brine-saturated specimens varies between 5% and 22%. The ultrasonic velocity measurements depict that samples with the same porosity values can have a broad range of velocity values. The resulting compaction trends in this study were compared to published compaction curves for synthetic mixtures of quartz and clay. All compaction trends show higher porosity reduction than the silt fraction with 100% quartz. Comparison of experimental compaction result of each mudstone and shale aggregate with its corresponding acquired well log data helps to delineate the burial history and exhumation in the study area. A net exhumation of 950 m and 800 m is estimated at Salina and Goliat wells, respectively. The outcomes of this study can provide insights for hydrocarbon prospect discovery in a pre-mature sedimentary basin in terms of exploration and production, and also for geological CO2 storage sites. The experimental results may provide information for well log and seismic interpretation, basin modeling and seal integrity of investigated horizons.

Progress in monitoring strategies for risk reduction in geologic CO2 storage

Commercial, demonstration and pilot geologic CO2 storage (GCS) projects have provided a wealth of practical experience in monitoring technologies. In this manuscript we review a few key projects, specific geophysical methods, well-based methods, geophysical workflows and some suggested best practices. These practices are often driven and governed by regulatory requirements (e.g. U.S. Environmental Protection Agency [US-EPA] Class VI underground injection regulation) and the need for effective reservoir management of pressures and volumes as well as the site-specific risks to containment, plume migration, and underground sources of drinking water. Reducing uncertainty in monitoring is likely to lead to reducing uncertainty in risk. One of our conclusions is the need for field experiment testing that is risk-driven. It is notable that GCS pilot projects have been designed for safe storage, and to date they have been successful. Technical challenges at all geologic CO2 storage sites include assuring injectivity and capacity predictions are reliable, the fate and subsurface topology of the CO2 plume is acceptable, regulatory permitting and compliance are accomplished in a timely manner, needed business assurances are supported by quantitative technical data, and the storage operation is acceptable to stakeholders. There is risk associated with all of these challenges necessitating a monitoring program utilizing both direct and indirect monitoring methods. Geophysical monitoring is viewed as a key component in approaching risk assessment because of the direct association of risk and monitoring in GCS. In this review we provide a framework for monitoring and then present some specific monitoring tools that may be useful for regulatory compliance, as well as technologies that are applicable to leakage detection. Since the Department of Energy National Risk Assessment Program (DOE NRAP) is focused on quantitative risk assessment, we focus on quantitative geophysical monitoring. Important concepts for a successful integration of monitoring and risk assessment include the following: Characterization of key parameters of risk and methods to monitor those parameters, the feedback between risk and monitoring, and the development of risk-based strategies to assess and update monitoring plans and tools. We briefly review current work in assessing uncertainty in important monitoring technologies, such as seismic and electrical geophysical surveys, and acknowledge that there is both temporal and spatial uncertainty in monitoring, in addition to the measurement uncertainty of specific tools. In our opinion monitoring approaches for subsurface imaging, such as 3D-reflection seismic, 3D-Vertical Seismic Profiling (VSP), cross well seismic, electromagnetic and electrical technologies, and well-log based measurements produce proxies for saturation and mass that, when properly calibrated and interpreted, are robust quantitative estimates of these key storage parameters. Understanding the uncertainty in these proxies is important in risk-driven monitoring. The cost of high-potential geophysical monitoring technologies impacts application of these methods to quantitative risk assessments. We therefore examine the concept of value of information (VOI) that is expected to play a role in selection of monitoring tools. We also conclude that monitoring of leakage scenarios has had minimal field validation and thus quantifying and reducing risk will require dedicated experiments that probe and test uncertainty in fault/fracture-zone and wellbore leakage.

Field test study on leakage monitoring at a geological CO2 storage site using hydrogen as a tracer

In this study, a new monitoring approach for detecting CO2 leakage is proposed that utilizes hydrogen gas as a tracer for CO2 geological storage. The gas leakage from a shallow formation is studied using 20–100-m deep boreholes at the Ito Natural Analog Site field testing facility in Fukuoka, Japan. Direct measurements of CO2 concentrations may yield unreliable results, particularly in summer when high levels of CO2 flux are produced from soil respiration. A gas mixture (CO2:H2/99:1) was injected through a well to the subsurface. The concentrations of gas emitted from the soil were measured in pipes where the gas was trapped; hydrogen was detected at 15ppm immediately in less than 30min after the mixed gas was released to the water-saturated zone. Repeated measurements were conducted in the area and elevated H2 levels of 15–65ppm were recorded for 2 weeks. CO2 measurements in the pipes showed elevated levels at one monitoring point a day after the mixed gas was released. The field result was confirmed by laboratory experiments of the mixed gas, verifying that H2 is detected earlier than CO2. The elapsed time between H2 and CO2 after the mixed gas released was observed in this study suggesting that H2 has a potential as signal precursor for a future of CO2 arrival. However, further experiment should be conducted to demonstrate the applicability of H2 as a monitoring tool in CCS.

Colorimetric pH Measurement of Pressurized Groundwater Containing CO2.

A gas-tight pH measurement is needed to monitor water chemistry at a CO2 geological storage site. In the CO2 reservoirs, the temperature and pressure are generally more than the critical point of CO2 (31.2°C and 7.38 MPa). In this study, a colorimetric pH measurement method was examined up to 20 MPa for future application to various CO2 reservoirs. A mixture of two color indicators, bromocresol green (BCG) and metacresol purple (mCP), was considered to be a suitable measurement method between pH 3 and 9. The uncertainty up to 20 MPa was less than 0.12 pH units without any correction of pressure effects. We demonstrated a pH measurement of formation water at the Nagaoka CO2 post-injection site. The pH measurement was successfully accomplished under a high-pressure condition (ca. 11 MPa) and without degassing of CO2.

Review: Role of chemistry, mechanics, and transport on well integrity in CO2 storage environments

Among the various risks associated with CO2 storage in deep geologic formations, wells are important potential pathways for fluid leaks and groundwater contamination. Injection of CO2 will perturb the storage reservoir and any wells that penetrate the CO2 or pressure footprints are potential pathways for leakage of CO2 and/or reservoir brine. Well leakage is of particular concern for regions with a long history of oil and gas exploration because they are top candidates for geologic CO2 storage sites. This review explores in detail the ability of wells to retain their integrity against leakage with careful examination of the coupled physical and chemical processes involved. Understanding time-dependent leakage is complicated by the changes in fluid flow, solute transport, chemical reactions, and mechanical stresses over decade or longer time frames for site operations and monitoring.Almost all studies of the potential for well leakage have been laboratory based, as there are limited data on field-scale leakage. Laboratory experiments show that CO2 and CO2-saturated brine still react with cement and casing when leakage occurs by diffusion only. The rate of degradation, however, is transport-limited and alteration of cement and casing properties is low. When a leakage path is already present due to cement shrinkage or fracturing, gaps along interfaces (e.g. casing/cement or cement/rock), or casing failures, chemical and mechanical alteration have the potential to decrease or increase leakage risks. Laboratory experiments and numerical simulations have shown that mineral precipitation or closure of strain-induced fractures can seal a leak pathway over time or conversely open pathways depending on flow-rate, chemistry, and the stress state. Experiments with steel/cement and cement/rock interfaces have indicated that protective mechanisms such as metal passivation, chemical alteration, mechanical deformation, and pore clogging can also help mitigate leakage. The specific rate and nature of alteration depend on the cement, brine, and injected fluid compositions. For example, the presence of co-injected gases (e.g. O2, H2S, and SO2) and pozzolan amendments (fly ash) to cement influences the rate and the nature of cement reactions. A more complete understanding of the coupled physical–chemical mechanisms involved with sealing and opening of leakage pathways is needed.An important challenge is to take empirically based chemical, mechanical, and transport models reviewed here and assess leakage risk for carbon storage at the field scale. Field observations that accompany laboratory and modeling studies are critical to validating understanding of leakage risk. Long-term risk at the field scale is an area of active research made difficult by the large variability of material types (cement, geologic material, casing), field conditions (pressure, temperature, gradient in potential, residence time), and leaking fluid composition (CO2, co-injected gases, brine). Of particular interest are the circumstances when sealing and other protective mechanisms are likely to be effective, when they are likely to fail, and the zone of uncertainty between these two extremes.

포항 지역 토양 CO<sub>2</sub>의 분포 및 거동 특성 연구: CO<sub>2</sub> 지중저장 부지 자연 배경 조사 및 예비 해석

Distribution and behavior of baseline soil CO2 were investigated in a candidate geologic CO2 storage site in Pohang, with measuring CO2 concentrations and carbon isotopes in the vadose zone as well as CO2 fluxes and concentrations through ground surface. This investigation aimed to assess the baseline CO2 levels and to build the CO2 monitoring system before injecting CO2. The gas in the vadose zone was collected using a peristaltic pump from the depth of 60 cm below ground surface, and stored at gas bags. Then the gas components (CO2, O2, N2, CH4) and δ 13 CCO2 were analyzed using GC and CRDS (cavity ringdown spectroscopy) respectively in laboratory. CO2 fluxes and CO2 concentrations through ground surface were measured using Li-COR in field. In result, the median of the CO2 concentrations in the vadose zone was about 3,000 ppm, and the δ 13 CCO2 were in the wide range between −36.9‰ and −10.6‰. The results imply that the fate of CO2 in the vadose zone was affected by soil property and vegetations. CO2 in sandy or loamy soils originated from the respiration of microorganisms and the decomposition of C3 plants. In gravel areas, the CO2 concentrations decreased while the δ 13 CCO2 increased because of the mixing with the atmospheric gas. In addition, the relation between O2 and CO2, N2, and the relation between N2/O2 and CO2 implied that the gases in the vadose zone dissolved in the infiltrating precipitation or the soil moisture. The median CO2 flux through ground surface was 2.9 g/m 2 /d which is lower than the reported soil CO2 fluxes in areas with temperate climates. CO2 fluxes measured in sandy and loamy soil areas were higher (median 5.2 g/m 2 /d) than those in gravel areas (2.6 g/m 2 /d). The relationships between CO2 fluxes and concentrations suggested that the transport of CO2 from the vadose zone to ground surface was dominated by diffusion in the study area. In gravel areas, the mixing with atmospheric gases was significant. Based on this study result, a soil monitoring procedure has been established for a candidate geologic CO2 storage site. Also, this study result provides ideas for innovating soil monitoring technologies.

Perturbative Studies to Calculate the Permeability and Porosity of a CO2 Storage Formation in a Data Shortage Context

Injection of CO2 in geological formations is widely recognized as a promising technology within the set of strategies to be developed to reduce the concentration of atmospheric CO2. The management of long-term safety related with Geological Storage of CO2 (CGS) should be an iterative and interactive on-going improvement process throughout the life of the project. This process, through application of appropriate methodologies, should establish a robust and reliable framework for identifying, assessing and managing each project phase. It plays a key role in both the definition and planning of CO2 injection strategies at any scale and in its operational, closure and post-closure stages.A key element to calculate the probability of leakage risk includes the interaction of the CO2 plume with potential flow paths or with risk elements. This requires obtaining the temporal evolution of the injected CO2 plume (dynamic probability). Sufficient understanding of the CO2 plume migration within the reservoir is essential to assess the risks of leakage for different injection scenarios. The stochastic simulation can be a valuable tool to achieve a sufficient understanding of the underlying mechanisms that control the behaviour of a system. However, it is not uncommon that using probabilistic modelization to make predictions of future behaviour of a system (predictive modelization) turns out to be a complex process. The CO2 plume evolution and structural and hydrodynamic trapping mechanisms are key elements in the safety of a site. These are determined by the number of gravity, Γ, a dimensionless parameter that measures the ratio between buoyancy and viscous forces, and which is defined from both operating and reservoir parameters and, among others, is a function of the injection rate.The models used in this work are based on published studies on CO2 injection from a single well into a deep permeable aquifer saturated with saline fluid (saline aquifer). The type of solution obtained is a function of the relationship between buoyancy and viscous forces. According to the injection rate, in viscous forces domain cases it is possible to decouple the petrophysical variables of the system that determine the advance of the plume (porosity and permeability) depending on the shape ratio of the plume (rmin/rmax or ratio between the radii at the bottom and top of the CO2 plume).This is a methodology that makes sense for applying it to the initial stages of characterization of potential CO2 geological storage sites in situations of shortages of data, which it is a common feature of deep saline aquifers. Hontomín site intends to be a demo site for CO2 injection in carbonate formations, these being the probable most promising CO2 geologic storage formation type in Spain. A basic characteristic of these sites is the lack of deep carbonate formations porosity and permeability data, critical variables especially in risk studies. This methodology has its scope in the injection phase for a preliminary characterization, before the start of a possible systematic characterization of the site prior to a potential industrial use. So, a study has been conducted to explore the possibility of using the perturbation of the system by the CO2 injection to get an upscaling of both porosity and permeability en grand of the storage formation from the in situ or laboratory characterization phases through stochastic modelling of the CO2 plume and the appropriate injection strategies within the range of viscous forces domain cases. This provides a reduction of the uncertainties in the calculation and adjustment of dynamic probabilities of both the plume advance and the pressure increase due to the injection of CO2. As a whole it will result in an improvement in the storage safety assessment

Reduced order models of transient CO2 and brine leakage along abandoned wellbores from geologic carbon sequestration reservoirs

We have developed reduced order models (ROMs) for CO2 and brine leakage rates along wellbores including abandoned wells at geologic CO2 storage sites using a Multivariate Adaptive Regression Splines (MARS) algorithm. The ROMs were developed for use within systems level performance assessment models such as Los Alamos National Laboratory's CO2-PENS model. The ROMs are used to compute leakage rates as a function of wellbore properties including effective permeability, depth as well as pressures and saturations in the reservoir where the wellbore intercepts the reservoir. The ROMs were created using results of complex, 3-D multi-phase numerical simulations of large-scale CO2 injection at a generic CO2 storage site with an abandoned wellbore. The generic site included not only the primary storage reservoir but also a groundwater aquifer and an intermediate permeable zone. Two sets of simulations were performed, one with and one without an abandoned wellbore in order to capture the effect of coupling between the storage reservoir and wellbore in a system level model where it is assumed that they are decoupled. Cross-validation against the complex, multi-phase numerical simulation results were used to evaluate the ability of the ROMs to reproduce numerical simulation results. Further, our ROM development approach effectively captures transient CO2 and brine leakage during and after CO2 injection as well as the effects of an intermediate permeable zone on leakage to a shallow groundwater aquifer and to the atmosphere. Ultimately, the ROM is a computationally efficient model that effectively captures many of the complex underlying processes taking place during CO2 and brine leakage along a wellbore at a geologic CO2 storage site.