Geosequestration Projects Research Articles

Underground carbon sequestration as a component of decarbonization in anthropogenic activity

The article discusses why it is appropriate to talk about carbon utilization even in cases where the goal is to reduce carbon dioxide emissions into the environment. An explanation is given as to why underground carbon dioxide burial (geosequestration) is the main feasible solution for the decarbonization of anthropogenic activity at the planetary scale. A brief review of existing or promising practices of carbon dioxide geosequestration is provided. The economic and technological aspects of the implementation of geosequestration projects, affecting their feasibility, are viewed, as well as the relevant statistics of such projects over the first two decades of the XXI century. In particular, the extremely low percentage of implementation of planned projects is noted in the majority of industrial sectors consuming fossil hydrocarbon fuels. The regional aspect of the problem is considered in relation to the work of industrial companies of the Perm Region and their foreign economic activity under the conditions of the enacted and planned legislation. The available potential of the regions’s subsoil for geosequestration of carbon dioxide is stated - oil collectors, coal seams of the sealed mines of the Kizelovsky basin, salt deposits of the Verkhnekamsky deposit.

Impact of nanoparticles–surfactant solutions on carbon dioxide and methane wettabilities of organic-rich shale and CO2/brine interfacial tension: Implication for carbon geosequestration

Rock wetting behaviour and CO2/brine interfacial tension (IFT) have significant impacts on enhanced hydrocarbon recovery (EOR) and carbon geo-sequestration (CGS) projects. Influence of nanoparticles/surfactant solutions (NPS) flooding on EOR and CGS in sandstone and carbonate formation have been examined in recent studies. But the impact of NPS on carbon dioxide (CO2) and methane (CH4) wettabilities of organic-rich shale and CO2/brine IFT is presently unclear. Thus, we measured contact angles, [advancing (θa) and receding (θr)] for CO2/brine and CH4/brine on Marcellus shale with high total organic carbon (14.8 wt%), as well as CO2/brine IFT with Krüss drop shape analyzer (DSA 100) through the sessile drop and pendant drop techniques. Prior to IFT and contact angles measurement, the shale samples were aged in NPS solutions to evaluate the impact of NPS treatment on CO2 geo-storage. Low-cost rice husk silica nanoparticles and saponin surfactant were used for the study due to their environmental friendliness and economic attractiveness. At geo-storage conditions (25 MPa and 353 K), the advancing contact angle of untreated shale was measured as θa=116.22° (CO2-wet condition), whereas the receding contact angle was measured as θr=82.88° (near neutral wettability). However, θa reduced by 56.34° whereas θr reduced by 56.76° when the shale substrate was treated with 0.1 wt% SiO 2 and 0. 2 wt% saponin solutions. CO2/NPS IFT were lower than CO2/brine IFT and the CH4 wettability of the Marcellus shale was significantly lower than the CO2 wettability at all investigated conditions. Contact angles decreased with temperature and increased with CO2/CH4 pressure, whereas CO2/NPS IFT exhibited an opposite trend. The reduction in contact angles and CO2/brine IFT by NPS have significant impacts on adsorption trapping of CO2 in organic-rich shale and hydrocarbon recovery from unconventional shale reservoirs.

An image-based coal network model for simulating hydro-mechanical gas flow in coal: An application to carbon dioxide geo-sequestration

CO2 geo-sequestration is a practical approach to achieve net-zero carbon target. However, one of the main challenges for successful CO2 geo-sequestration is the reduced coal permeability and injectivity that are caused by coal swelling. Coal has complex and heterogenous internal pore and fracture structure. The processes of gases adsorbing, desorbing, and transporting within multiscale heterogeneous coal structures are more complicated compared with conventional rocks. This paper aims to gain insights about the gas transport behaviours in coal by developing a coupled model to simulate gas flow multiphysics as well as dynamic coal deformation. This work develops an image-based 3D fracture network model, called Fracture Box Model (FBNM). In this model, each fracture is described by arrays of box elements such that the regional change of fracture opening widths can be preserved. Compared with other fracture models (e.g. discrete fracture network), FBNM can simulate complicated multiphysical gas transport more efficiently, but also be able to simulate corresponding coal matrix deformation. By comparing permeability results between direct simulation method with FBNM, it is found that FBNM can effectively estimate the permeability of original fracture networks, but requiring significantly less computational cost. To study the implications of gas types, effective stress, gas adsorption, and thermal expansion on coal permeability, gas injection pressures, gas types, coal seam temperatures are varied and investigated in the simulations. In addition to the advantage of computational efficiency, FBNM is more preferable for complicated flow transport simulations where direct simulation methods are still challenging. This work provides a promising framework which could be further developed for multiphase and multicomponent flow simulations for CO2 geo-sequestration projects.

Seismic monitoring of CO2 geosequestration using multi-well 4D DAS VSP: Stage 3 of the CO2CRC Otway project

An important part of any CO2 geosequestration project is to ensure CO2 containment and conformance in the subsurface. This is generally done by implementing a comprehensive, risk-based Measurement, Monitoring and Verification plan, a key element of which is active time-lapse seismic monitoring. However, high cost and environmental impact of the standard surface seismic monitoring dictate the need for a cost-effective and environmentally friendly alternative. An opportunity to develop such method emerges with advances in distributed acoustic sensing (DAS) technology, which turns an optical fibre into a seismic sensor with dense spatial sampling. DAS can be permanently deployed in multiple wells across the geosequestration site providing a robust and non-intrusive network of seismic receivers. This approach was developed and tested in the CO2CRC Otway project, where injection of 15 kt of CO2 at 1.5 km depth was monitored with a 4D vertical seismic profiling (VSP) using five borehole DAS arrays and mobile vibroseis sources. The 4D DAS VSP in each of the five wells provides broadly consistent images of the CO2 plume with some differences due to different illumination of the target horizon, lateral variation of velocities, and seismic anisotropy. When the newly injected CO2 reaches a CO2 plume created as a result of an earlier injection into the same formation ∼600 m updip, 4D DAS VSP shows a change in reflectivity in that area and beyond. This shows a potential of 4D DAS VSP for monitoring gas injection into gas-saturated reservoirs.

Unsupervised learning monitors the carbon-dioxide plume in the subsurface carbon storage reservoir

Subsurface sequestration of carbon dioxide (CO2) requires long-term monitoring of the injected CO2 plume to prevent CO2 leakage along the wellbore or across the caprock. Accurate knowledge of the location and movement of the injected CO2 is crucial for risk management at a geological CO2-storage complex. Conventional methods for locating/assessing the injected CO2 plume in the subsurface assume a geophysical model, which is specific and may not be applicable to all types of CO2-injection reservoirs and scenarios. We developed an unsupervised-learning-based visualization of the subsurface CO2 plume that adapts and scales based on the data without requiring an assumption of the geophysical model. The data-processing workflow was applied to the cross-well seismic tomography data from the SECARB Cranfield carbon geo-sequestration project. A multi-level clustering approach was developed to account for data imbalance due to the absence of CO2 in the large portion of the imaged reservoir. The first level of clustering differentiated CO2-bearing regions from the non-CO2 bearing regions and achieved a silhouette score of 0.88, a Calinski-Harabasz index of 271145, and a Davies-Bouldin index of 0.30, which are indicative of high quality, reliable clustering. The second level of clustering further differentiated the CO2-bearing regions into regions containing low, medium–low, medium–high, and high CO2 content. Overall, the multi-level clustering achieved a silhouette score, Calinski-Harabasz index, and Davies-Bouldin index of 0.68, 86750, and 0.46, which confirm the high quality and reliability of the newly proposed unsupervised-learning-based visualization. Three distinct clustering techniques, namely k-means, mean-shift, and agglomerative, generated similar visualizations. In terms of the adjusted Rand index, the similarity of clusters identified by the three distinct clustering techniques is around 0.98, which indicates the robustness of the cluster labels assigned to various regions of the geological carbon-storage reservoir. Further, we find certain geophysical signatures, such as Fourier transform and wavelet transform, represent the distribution of CO2 content in subsurface.

Interaction of low salinity surfactant nanofluids with carbonate surfaces and molecular level dynamics at fluid-fluid interface at ScCO2 loading

HypothesisThe advanced low salinity aqueous formulations are yet to be validated as an injection fluid for enhanced oil recovery (EOR) from the carbonate reservoirs and CO2 geosequestration. Interaction of various ionic species present in the novel low salinity surfactant nanofluids with scCO2/CO2 saturated aqueous phase interface and at the interface of CO2 saturated aqueous phase/mixed wet (with CO2 and Decane) limestone surface at the conditions of low salinity at reservoir conditions are to yet to be understood. ExperimentsThis study, carried out for the first time in low salinity at scCO2 loading conditions at 20 MPa pressure and 343 K temperature, comprises of wettability study of the limestone surface by aqueous phase contact angle measurements using ZrO2 nanoparticles (in the concentration range of 100–2000 mg/L) and 0.82 mM Hexadecyltrimethylammonium bromide (CTAB) surfactant. Molecular dynamics simulations results were used to understand the underlying mechanism of wettability alteration and interfacial tension (IFT) change. FindingsThis study reveals that a low dosage (100 mg/L) of ZrO2 nanoparticles forming ZrO2-CTAB nano-complexes helps in wettability alteration of the rock surface to more water-wetting state; certain ionic species augment this effect when used in appropriate concentration. Also, these nano-complexes helps in scCO2/CO2 saturated aqueous phase IFT reduction. This study can be used to design advanced low salinity injection fluids for water alternating gas injection for EOR and CO2 geosequestration projects.

4D surface seismic monitoring the evolution of a small CO2 plume during and after injection: CO2CRC Otway Project study

Time lapse seismic is a vital component of the monitoring and verification of virtually any geosequestration project. Stage 2C of the CO2CRC Otway project is designed to test the limits of land 3D time-lapse (4D) seismic in the monitoring of small-scale CO2 injection. The 4D seismic monitoring program of Stage 2C of the Otway Project includes a baseline survey (BL); three monitor surveys (M1–M3) obtained during the injection of CO2-rich gas into the saline aquifer at a depth of 1.5 km at the injection intervals of 5, 10, and 15 kt; and two post-injection surveys (M4 and M5), acquired one and two years after the end of injection. Reliable time-lapse changes among the 4D surveys were obtained using a buried receiver array. Analysis of the seismic cubes and attributes demonstrates that during and after injection the plume spreads laterally only in southeastern direction. The results demonstrate strong time-lapse signal corresponding to the injection level and the absence of any observed leakage into the overburden. The plume evolution is reliably observed and traced from M1 to M5 surveys with most of the changes occurring between the BL and M4 surveys.

CO2-brine-caprock interaction: Reactivity experiments on mudstone caprock of South-west Hub geo-sequestration project

This study aims at focusing on the geo-chemical reactions of caprock upon injection of supercritical CO2 (ScCO2) under deep saline aquifer's conditions. The caprock samples were obtained at a depth of 979 m in the DMP Harvey-2 well, which is recognized as mudstone in the Lesueur Formation of the South-west Hub geo-sequestration project located 120 kilometres south of Perth in Australia. Geo-chemical reactions were conducted in a reaction chamber to determine the chemical reactivity of brine-saturated caprock under actual reservoir conditions (40 °C, 10 MPa and salinity 4.5%). The reaction was conducted at 10 MPa ScCO2 pressure and allowed for 37 weeks. The reacted fluid samples were subjected to several chemical analyses, including alkalinity tests, pH measurements and inductively-coupled plasma optical emission spectrometry (ICP-OES) tests. The solid minerals were tested using X-ray Diffraction (XRD), Scanning electron microscopy (SEM) and Energy-Dispersive X-ray (EDX) to obtain a better understanding related to of their chemical characterization of the caprock. Finally, a geochemical model (PHREEQC) was developed to forecast mineral dissolution/precipitation equilibrium and redox reactions.Fluid chemistry showed that the concentration of major elements such as Ca, Mg and K increased with time due to the dissolution of minerals such as K-feldspar, anorthite, and chlorite. On the other hand, the release concentration of Si, Fe and Al ions decreased with time due to the precipitation of secondary minerals such as kaolinite, gibbsite, amorphous silica and Fe(OH)3. Accordingly, the dissolution of minerals is very significant compared to precipitation of secondary minerals in the short term which can increase the pore volume of the caprock.

Locating the gas leakage source in the atmosphere using the dispersion wave method

A new and simple method for locating emission source was proposed in this work based on gas dynamic dispersion information. The simulation of the unsteady state dispersion of leakage gas emission from the geosequestration project showed that the transportation process of emission gases in the atmosphere is similar to wave propagation, and the time parameter of the dispersion wave is linearly related to the downwind distance. Therefore, monitoring the dispersion wave at different downwind positions can be used to estimate the leakage source position. An estimation formula for locating emission sources was derived. First, an estimation formula for locating emission sources was derived under some initial assumptions. Then, the deviation of the location formula was investigated using a computational fluid dynamics (CFD) model and analytic solution to get the offset distance under different conditions. The results showed that the average distance is stable for a certain atmosphere and terrestrial conditions. This method needs no more than 3 sensors’ dynamic information to locate the emission source, and hence it is highly useful for conditions with limited sensors. A numerical test demonstrated that the absolute error of the source estimation is within the range of 1–30 m. Finally, experimental tests were conducted to verify the feasibility of the source location with dispersion waves. Therefore, the dispersion wave monitor is a potentially simple and feasible way to estimate the source location for gas emission event management with limited sensors in the process industries.

Estimation of the current stress field and fault reactivation analysis in the Asmari reservoir, SW Iran

Knowing the current condition of the faults and fractures in a reservoir is crucial for production and injection activities. A good estimation of the fault reactivation potential in the current stress field is a useful tool for locating the appropriate spot to drill injection wells and to calculate the maximum sustainable pore pressure in enhanced oil recovery and geosequestration projects. In this study, after specifying the current stress state in the Gachsaran oilfield based on Anderson’s faulting theory, the reactivation tendency of four faults (F1, F2, F3, and F4) in the Asmari reservoir is analyzed using 3D Mohr diagrams and slip tendency factors. Results showed that all the faults are stable in the current stress state, and F2 has the potential to undergo the highest pore pressure build-up in the field. On the other hand, F3 has the proper conditions (i.e., strike and dip referring to σHmax orientation) for reactivation. Stress polygons were also applied to show the effect of the pore pressure increase on fault stability, in a graphical manner. According to the results, the best location for drilling a new injection well in this part of the field is the NW side of F2, due to the lower risk of reactivation. It was found that both methods of 3D Mohr diagrams and slip tendency factors predict similar results, and with the lack of image logs for stress orientation determination, the slip tendency method can be applied. The results of such studies can also be used for locating safe injection points and determining the injection pressure prior to numerical modeling in further geomechanical studies.

Impact of nanoparticles on the CO2-brine interfacial tension at high pressure and temperature

HypothesisNanofluid flooding has been identified as a promising method for enhanced oil recovery (EOR) and improved Carbon geo-sequestration (CGS). However, it is unclear how nanoparticles (NPs) influence the CO2-brine interfacial tension (γ), which is a key parameter in pore-to reservoirs-scale fluid dynamics, and consequently project success. The effects of pressure, temperature, salinity, and NPs concentration on CO2-silica (hydrophilic or hydrophobic) nanofluid γ was thus systematically investigated to understand the influence of nanofluid flooding on CO2 geo-storage. ExperimentsPendant drop method was used to measure CO2/nanofluid γ at carbon storage conditions using high pressure-high temperature optical cell. FindingsCO2/nanofluid γ was increased with temperature and decreased with increased pressure which is consistent with CO2/water γ. The hydrophilicity of NPs was the major factor; hydrophobic silica NPs significantly reduced γ at all investigated pressures and temperatures while hydrophilic NPs showed only minor influence on γ. Further, increased salinity which increased γ can also eliminate the influence of NPs on CO2/nanofluid γ. Hence, CO2/brine γ has low, but, reasonable values (higher than 20 mN/m) at carbon storage conditions even with the presence of hydrophilic NPs, therefore, CO2 storage can be considered in oil reservoirs after flooding with hydrophilic nanofluid.The findings of this study provide new insights into nanofluids applications for enhanced oil recovery and carbon geosequestration projects.

Recognition of leak CO 2 with wavelet analysis based on correlation monitoring between CO 2 and O 2 in atmosphere

Abstract It is necessary to monitor and identify CO2 leakage from geosequestration project. Some experiments were designed to test the feasibility of characterization and recognition method for CO2 leakage based on correlation analysis between atmospheric CO2 and O2. The monitoring results showed that atmospheric CO2 had a good linear relationship with O2, especially in the day time. The variations of CO2 and O2 were influenced by the weather condition. The results of emission experiments proved the capability of coupling monitoring atmospheric CO2 and O2 to recognize the abnormal CO2 signal due to leakage. Moreover, two parameters, ALF (apparent leakage flux) and ALFs (apparent leakage flux based on surplus variable) were used to distinguish CO2 leakage in real time. The monitoring results verified that it was feasible to identify CO2 leakage with these two parameters. Compared with the results after median filter, the abrupt leakage signal can be more easily recognized with that after wavelet filter. ALFs can be applied to estimate the elevated concentration due to leakage, which can also be predicted by interpolating with related variation of atmospheric O2. ALF reflects the relative leakage rate. Therefore, it is practicable to identify leakage event in real time with the method proposed in this paper.

The impact of partition coefficient data on the interpretation of chemical tracer behaviour in carbon geosequestration projects

Partition (or distribution) coefficients determine the relative equilibrium concentrations of chemical constituents (or chemical tracers) in each of the phases of a multi-phase system under dilute conditions. The various fluid phases in a reservoir have differing transport properties (e.g. varying relative permeability) and to correctly interpret the behaviour of injected chemical tracers it is essential that accurate partition coefficients are known. In the context of carbon geosequestration or long-term storage of CO2, chemical tracers will be predominantly exposed to an environment consisting of supercritical CO2 and formation water as the main fluid phases. To estimate/simulate the reservoir properties relevant to injected CO2 tagged with chemical tracers, it is therefore necessary to incorporate high pressure/temperature CO2/water partition coefficients into any model/simulation. In this paper, we present a method to determine these partition coefficients for gaseous chemical tracers using a variation of the widely used EPICS (or equilibrium partitioning in a closed system) method. With this method, only the concentration in one phase (in this case, CO2) needs to be measured. We then report these values for a series of representative chemical tracers (i.e. krypton, xenon, sulfur hexafluoride, perdeuterated methane and R134a) at pressure/temperature conditions that have been previously used at the CO2CRC's Otway CCS demonstration project in Victoria, Australia. These values were generally lower than the corresponding Henry's Law coefficients at comparable temperatures. Experiments also examined the impact of adding CH4 to the system to mimic feedstock gas at the CO2CRC Otway project and provide data pertinent to scenarios where CO2 is injected into depleted CH4 gas fields. These values are compared with Henry's Law coefficients and another recently published set of high pressure/temperature partition coefficients. With computational simulations, we have shown that these differences are potentially significant and demonstrate their impact in three typical CO2 geo-sequestration scenarios (i.e. injection into two types of aquifers and injection into a depleted reservoir with a gas cap).

An experimental evaluation of unique CO2 flow behaviour in loosely held fine particles rich sandstone under deep reservoir conditions and influencing factors

Lack of understanding of CO2 flow behaviour in loosely bonded fine particles (clay and mineral fragments) rich sandstone formations has limited the optimum usage and the operational efficiency of various CO2 injection-related field applications in these formations. A comprehensive experimental study including core flooding tests, XRD and SEM image analysis was therefore conducted precisely to understand the CO2 flow behaviour in sandstone formations rich with loosely bonded clay and detrital particles. 210 mm long sandstone cores obtained from the Marburg Formation, eastern Australia were flooded with CO2 at a range of temperatures (24–54 °C) and confining pressures (10–60 MPa). Pressure developments along the cores were monitored to identify the fluid migration patterns through the samples. According to the results, CO2 permeability in tested sandstone has a high tendency to decrease with increasing injection pressure, depth (confining pressure) and temperature. Increased confining pressure and temperature caused 40–50% and 10–30% reductions in the CO2 permeability. This is because the permeability of fine-rich sandstone is highly affected by fine particle migration associated increased flowing fluid viscosity, pore shrinkage with fine clay particle accumulations and easy compaction of soft clay minerals. Moreover, the closure of micro-cracks under high confining stresses, CO2 adsorption created by clay swelling, the occurrence of electric double layers around clay minerals and a reduced CO2 slip effect are also affect the permeability reduction. Many of these effects were identified in the micro-scale study conducted using SEM image analysis. Interestingly, the injection of CO2 at higher pressures (>6 MPa) caused the pressure development in the sample to be held for a significant time due to the blocking of CO2 flow by the accumulation of transported clay particles in pores. This pressure holding period lasts until sufficient pressure development occurs at the upstream side of the barrier to initiating a fluid flow by breaking that barrier. The findings of the study will be very useful for advances in numerical modelling and analytical equations and worldwide CO2 geosequestration projects in fine-rich sandstone aquifers.

Fracturing-hydraulic coupling in transversely isotropic rocks and a case study on CO2 sequestration

This paper outlines a two-dimensional displacement discontinuity method (DDM) for transversely isotropic elastic materials and a direction-dependent criterion for fracturing in anisotropic rocks. These are combined to analyse fracturing processes in transversely isotropic rocks. The fracturing analysis is then coupled with equations for fluid flow in fractures to study the interactions of the fluid flow and rock mass deformation. These functionalities have been implemented into an existing computing code FRACOD.We describe results from application of the fracturing-hydraulic coupling model for transversely isotropic rocks in a detailed case study of a CO2 geo-sequestration project in Australia. Existing fault re-activation and the cap-rock stabilities have been studied in detail. Modelling predicts that the site is stable under the injection conditions and this agrees with other simulations and site monitoring data.

CO2wettability of seal and reservoir rocks and the implications for carbon geo-sequestration

We review the literature data published on the topic of CO2 wettability of storage and seal rocks. We first introduce the concept of wettability and explain why it is important in the context of carbon geo-sequestration (CGS) projects, and review how it is measured. This is done to raise awareness of this parameter in the CGS community, which, as we show later on in this text, may have a dramatic impact on structural and residual trapping of CO2. These two trapping mechanisms would be severely and negatively affected in case of CO2-wet storage and/or seal rock. Overall, at the current state of the art, a substantial amount of work has been completed, and we find that: Sandstone and limestone, plus pure minerals such as quartz, calcite, feldspar, and mica are strongly water wet in a CO2-water system. Oil-wet limestone, oil-wet quartz, or coal is intermediate wet or CO2 wet in a CO2-water system. The contact angle alone is insufficient for predicting capillary pressures in reservoir or seal rocks. The current contact angle data have a large uncertainty. Solid theoretical understanding on a molecular level of rock-CO2-brine interactions is currently limited. In an ideal scenario, all seal and storage rocks in CGS formations are tested for their CO2 wettability. Achieving representative subsurface conditions (especially in terms of the rock surface) in the laboratory is of key importance but also very challenging.

CO2 Leakage Identification in Geosequestration Based on Real Time Correlation Analysis Between Atmospheric O2 and CO2

The paper describes a method for monitoring CO2 leakage in geological carbon dioxide sequestration. A real time monitoring parameter, apparent leakage flux (ALF), is presented to monitor abnormal CO2 leakage, which can be calculated by atmospheric CO2 and O2 data. The computation shows that all ALF values are close to zero-line without the leakage. With a step change or linear perturbation of concentration to the initial CO2 concentration data with no leakage, ALF will deviate from background line. Perturbation tests prove that ALF method is sensitive to linear perturbation but insensitive to step change of concentration. An improved method is proposed based on real time analysis of surplus CO2 concentration in least square regression process, called apparent leakage flux from surplus analysis (ALFs), which is sensitive to both step perturbation and linear perturbations of concentration. ALF is capable of detecting concentration increase when the leakage occurs while ALFs is useful in all periods of leakage. Both ALF and ALFs are potential approaches to monitor CO2 leakage in geosequestration project.

Application of diffracted wave analysis to time‐lapse seismic data for CO2 leakage detection

ABSTRACTTime‐lapse seismic analysis is utilized in CO2 geosequestration to verify the CO2 containment within a reservoir. A major risk associated with geosequestration is a possible leakage of CO2 from the storage formation into overlaying formations. To mitigate this risk, the deployment of carbon capture and storage projects requires fast and reliable detection of relatively small volumes of CO2 outside the storage formation. To do this, it is necessary to predict typical seepage scenarios and improve subsurface seepage detection methods. In this work we present a technique for CO2 monitoring based on the detection of diffracted waves in time‐lapse seismic data. In the case of CO2 seepage, the migrating plume might form small secondary accumulations that would produce diffracted, rather than reflected waves. From time‐lapse data analysis, we are able to separate the diffracted waves from the predominant reflections in order to image the small CO2 plumes. To explore possibilities to detect relatively small amounts of CO2, we performed synthetic time‐lapse seismic modelling based on the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) Otway project data. The detection method is based on defining the CO2 location by measuring the coherency of the signal along diffraction offset‐traveltime curves. The technique is applied to a time‐lapse stacked section using a stacking velocity to construct offset‐traveltime curves. Given the amount of noise found in the surface seismic data, the predicted minimum detectable amount of CO2 is 1000–2000 tonnes. This method was also applied to real data obtained from a time‐lapse seismic physical model. The use of diffractions rather than reflections for monitoring small amounts of CO2 can enhance the capability of subsurface monitoring in CO2 geosequestration projects.

Common Themes in Risk Evaluation Among Eight Geosequestration Projects

Risk-evaluation workshops were held during early stages of eight carbon dioxide (CO2) geosequestration (GS) projects. For all projects, the primary entities evaluated were Features, Events, and Processes (FEPs), which are broad concepts pre-selected for their relevance to GS and to each project. Scenarios were later evaluated in some projects, but this paper addresses only the FEPs data.Design features for all risk workshops included information sharing, participation of 15 to 30 project experts and stakeholders, defined risk receptors (project values), categorical five-point scales of Severity and Likelihood (whose product is the quantity “risk”), and personal expertise ratings. Project values included health and safety of workers, public, and the environment, and usually include budget and schedule, contribution to research goals, and contribution to creating a successful GS industry. A fundamental result for each project was a FEPs ranking in terms of risk to project values.Workshops are not laboratories, and their characteristics may contain important variables. Nevertheless, their quantitative data enable comparing projects on a risk basis, comparing evaluations from experts and non-experts, and seeking commonalities among higher-risk areas in multiple projects. Data subsets are compared based on (1) the density of (Severity, Likelihood) value pairs among the 25 grid cells of a risk matrix, and (2) a cumulative plot of risk from the lowest-risk to the highest-risk FEPs.Data subsets from experts, non-experts, and each separate project show a concentration of risk values at low to moderate levels. Relative to experts, non-experts’ evaluations are slightly concentrated toward medium likelihood and away from medium severity. Among the eight projects, some show a greater incidence of low- to moderate-risk FEPs among their total FEPs lists. While it is these apparently lower- risk projects that have been more successful so far, this paper does not attempt to account for the potential effect of risk-evaluation thoroughness.In each project, some of the highest risks relate to managing a complex of activities and organizations, and to obtaining legal permissions and social license. This suggests that the ability of a GS industry to abate greenhouse gases most depends on addressing programmatic risks. Among physical hazards, those typically judged highest are related to driving, construction, and well drilling, rather than to CO2 itself. Regarding storage characteristics, for the eight selected project sites (evaluated from regional geology and prior to injection-well drilling) the adequacy of injectivity has been judged to pose greater risk than adequacy of capacity.

Molecular dynamics computations of brine–CO2 interfacial tensions and brine–CO2–quartz contact angles and their effects on structural and residual trapping mechanisms in carbon geo-sequestration

In the context of carbon geo-sequestration projects, brine–CO2 interfacial tension γ and brine–CO2–rock surface water contact angles θ directly impact structural and residual trapping capacities. While γ is fairly well understood there is still large uncertainty associated with θ. We present here an investigation of γ and θ using a molecular approach based on molecular dynamics computer simulations. We consider a system consisting of CO2/water/NaCl and an α-quartz surface, covering a brine salinity range between 0 and 4molal. The simulation models accurately reproduce the dependence of γ on pressure below the CO2 saturation pressure at 300K, and over predict γ by ∼20% at higher pressures. In addition, in agreement with experimental observations, the simulations predict that γ increases slightly with temperature or salinity. We also demonstrate that for non-hydroxylated quartz surfaces, θ strongly increases with pressure at subcritical and supercritical conditions. An increase in temperature significantly reduces the contact angle, especially at low-intermediate pressures (1–10MPa), this effect is mitigated at higher pressures, 20MPa. We also found that θ only weakly depends on salinity for the systems investigated in this work.